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Home My WebLink About206-0881. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: drifts / bailing Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 9,600 feet 7,532 feet true vertical 7,987 feet see schematic feet Effective Depth measured 8,090 feet 4,569; 5,090 feet true vertical 6,478 feet 3,028; 3,498 feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic 4-1/2" 12.6# / L-80 4,569' MD 4,569' TVD Tubing (size, grade, measured and true vertical depth)2-3/8" VS 4.7# / L-80 5,106' MD 3,513' TVD ZXP Liner Pkr; 4,569' MD 3,028' TVD Packers and SSSV (type, measured and true vertical depth)WL Pkr; N/A 5,090' MD 3,498' TVD N/A; N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Taylor Wellman 777-8449 Contact Name:Ryan Rupert Authorized Title:Operations Manager Contact Email: Contact Phone:777-8503 WINJ WAG 0 Water-Bbl MD 91' 1,630' 9,595' 0 Oil-Bbl measured true vertical Packer 4-1/2" 3,219' measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Ninilchik Field / Beluga-Tyonek GasN/A measured TVD Tubing Pressure 510 Ninilchik Unit Susan Dionne 5 N/A FEE-CIRI; C-061505; FEE-Private (surface) 4,788' Plugs Junk STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 206-088 50-133-20562-00-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 2. Operator Name:Hilcorp Alaska, LLC 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 321-243 832 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 0 Authorized Signature with date: Authorized Name: 0 Casing Pressure Liner 5,026' 0 7,982' 0 Representative Daily Average Production or Injection Data 91' 1,630' 4,788' Conductor Surface Intermediate Production 7,500psi Casing Structural 20" 9-5/8" 7" Length 7,240psi 5,750psi Collapse 1,500psi 3,090psi 5,410psi ryan.rupert@hilcorp.com Senior Engineer:Senior Res. Engineer: 8,930psi Burst 3,060psi91' 1,298' t Fra O 6. A G L PG , R Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 9:31 am, Jul 15, 2021 ManagerManagerranageraDigitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.07.14 16:58:41 -08'00' Taylor Wellman (2143) SFD 7/16/2021RBDMS HEW 7/20/2021 DSR-7/15/21BJM 9/29/21 Rig Start Date End Date 6/9/21 6/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name SD-05 50-133-20562-00-00 206-088 06/16/2021 - Wednesday Arrive on location. Safety meeting. RU SL unit. Open tree valves. Equalize IA w/ tbg @ 580 psi. RIH w/ 10' X 1½" weight bar / 1½" knuckle / 1½" jars / 1½" short spangs / 1.75" gauge ring. Liquid level 4,300'. Tag 5,022 RKB. No tool action downhole. Spang down 10X. POOH. Small marks on gauge ring. Install extra 5' roller bar. RIH w/ 5' X 1½" roller w/ 1.85" wheels / 10' X 1½" weight bar / 1½" knuckle / 1½" jars / 1½" short spangs / 1.75" impression block. Tag @ -9 ft. Can't get impression block thru tree. 4" tree with 2" hole. RIH w/ 5' X 1½" roller w/ 1.85" wheels / 10' X 1½" weight bar / 1½" knuckle / 1½" jars / 1½" short spangs / 1.75" drive down bailer. Tag @ 5,022 RKB. Spang down on bailer 10X. Down hole action very poor. POOH. Dents in mule shoe. Clean up shoe. RIH w/ 5' X 1½" roller w/ 1.85" wheels / 10' X 1½" weight bar / 1½" knuckle / 1½" jars / 1½" short spangs / 1.75" drive down bailer. Tag @ 5,023 RKB. Spang down on bailer 10X. Down hole action very poor. POOH. More dents in shoe. RIH w/ 5' X 1½" roller w/ 1.85" wheels / 10' X 1½" weight bar / 1½" knuckle / 1½" jars / 1½" short spangs / 0.75" spear. Tag @ 5,025 RKB. Spang down 25X. POOH. RIH w/ 5' X 1½" roller w/ 1.85" wheels / 10' X 1½" weight bar / 1½" knuckle / 1½" jars / 1½" short spangs / 1.75" drive down bailer. Take pull weight @ 4,900'. Line skipping really bad in stuffing box. Stuffing box full of Beluga mud. POOH. Lay down lubricator. Re- pack stuffing box. Stuffing box full of Beluga mud. Re-tie rope socket. Pickup lubricator. RIH w/ 5' X 1½" roller w/ 1.85" wheels / 10' X 1½" weight bar / 1½" knuckle / 1½" jars / 1½" short spangs / 1.75" drive down bailer. Can't RIH. POOH. Pump 50 gallons of diesel. RIH w/ 5' X 1½" roller w/ 1.85" wheels / 10' X 1½" weight bar / 1½" knuckle / 1½" jars / 1½" short spangs / 1.75" drive down bailer. Tag @ 5,026 RKB. Spang down 25X. POOH. Liquid level 4,000'. RIH w/ 5' X 1½" roller w/ 1.85" wheels / 10' X 1½" weight bar / 1½" knuckle / 1½" jars / 1½" short spangs / 1.75" drive down bailer. Tag @ 5,027 RK. Spang down 25X. POOH. Lay down for nite. 06/09/2021 - Wednesday 9:00, Halliburton E-line arrived at Susan Dionne, PTW, PJSM, Job scope. 9:30, Rig up E-line, PT 250psi lo 2,500psi hi. Had to change O-ring on lubricator. 12:20, RIH with CH/17' of 1.69" WT bar, CCL & 1.75" GR. Tag at 5,028' Just above sliding sleeve, POOH, find partial soap stick in 1.75" GR. Drop 1.75" gr and install 1.69" pressure cap on bottom of CCL. 13:45 RIH, tag at same 5,028', POOH, E-line standby. Discuss options with town, decide to pump 1.5bbl water to dissolve remaining soap. 16:35, RIH with same tool, tag at same 5,028'. Talk to town again and decide not to attempt to run strip guns past obstruction until after SL work. Tag at 5,028' J Rig Start Date End Date 6/9/21 6/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name SD-05 50-133-20562-00-00 206-088 Arrive on location. Safety meeting. RU SL unit. Open tree valves. Equalize IA w/ tbg @ 600 psi.RIH w/ 6' 1½" weight bar / 5' X 1½" roller w/ 1.85" wheels / 10' X 1½" weight bar / 1½" knuckle / 1½" jars / 1½" short spangs / 1.75" drive down bailer. Tag 5,024 RKB. Spang down 25X. Very sticky. POOH. RIH w/ 6' 1½" weight bar / 5' X 1½" roller w/ 1.85" wheels / 10' X 1½" weight bar / 1½" knuckle / 1½" jars / 1½" short spangs / 1.75" drive down bailer. Tag 5,024 RKB. Spang down 25X. POOH. RIH w/ 6' 1½" weight bar / 5' X 1½" roller w/ 1.85" wheels / 10' X 1½" weight bar / 1½" knuckle / 1½" jars / 1½" short spangs / 1.75" drive down bailer. Tag 5,024 RKB. Spang down 25X. POOH. Install only PIT and pressure cap on tree. Install pressure gauge in top of pressure cap. Open tbg to bleed down tank @ 600 psi. IA pressure 658 psi. Draw tbg down to bleed down tank and facility to 150 psi. IA pressure 330 psi. Well lifting liquid. Tool down for gauge ring run. RIH w/ 6' 1½" weight bar / 5' X 1½" roller w/ 1.85" wheels / 1½" knuckle / 1½" jars / 1½" short spangs / 1.75" gauge ring. Tag @ 5,040 RKB. SSD depth. POOH. RIH w/ 6' 1½" weight bar / 5' X 1½" roller w/ 1.85" wheels / 1½" knuckle / 1½" jars / 1½" short spangs / 5' X 1½" weight bar / 0.75" spear. Tag 5,040 RKB. Spang down 25X. POOH. RIH w/ 6' 1½" weight bar / 5' X 1½" roller w/ 1.85" wheels / 1½" knuckle / 1½" jars / 1½" short spangs / 1.75" drive down bailer. Tag 5,040 RKB. Spang down 25X. POOH. Lay down for nite. 06/17/2021 - Thursday Hilcorp decided not to add perfs because of the fill encountered. Sundry is being closed out without any of the Sundried perfs having been shot. bjm _____________________________________________________________________________________ Updated by CRR 05-13-21 SCHEMATIC Cook Inlet Basin, Alaska Middle Ground Shoal Last Completed: 02-28-1992 Oil Well ->Water injector -> Gas producer for Platform Ninilchik Unit Susan Dionne 05 PTD: 206-088 API: 50-133-20562-00-00 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Perf’d Status BLG-120 5,128’ 5,138’ 3,534’ 3,543’ 10 4/27/21 Open 5,152’ 5,162’ 3,556’ 3,566’ 10 4/27/21 Open 5,163’ 5,173’ 3,567’ 3,576’ 10 2/21/13 Open BLG-134 5,247’ 5,257’ 3,647’ 3,656’ 10 2/21/13 Open BLG-135 5,317' 5,343' 3,714' 3,739' 26' 6/7/07 Open Tyonek Sqz Holes 5,735' 5,737' 4,123' 4,125' 2' 8/8/06 Patched (10/27/06) & Cement isolated (6/1/07) T-65 8,270' 8,276' 6,657' 6,663' 6' 10/3/06 Patched (10/25/06) & Cement isolated (6/1/07) T-83 8,508' 8,524' 6,895' 6,911' 16' 10/3/06 Cmt isolated (07’) T-140 9,263' 9,289' 7,650' 7,676' 26' 10/3/06 Cmt isolated (07’) Zon BLG-1 BLG-1 BLG-1 Tyon Sqz Ho T-6 T-8 T-14 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 133# / K-55 / PE 18.73” Surf 91' 9-5/8" Surface 40# / L-80 / BTC 8.835” Surf 1,630' 7" Intermediate 26# / L-80 / BTC 6.276” Surf 4,788' 4-1/2" Liner 12.6# / L-80 / Hydril 563 3.958” 4,569' 9,595' TUBING DETAIL 4-1/2" Tubing 12.6#/L-80/Buttress Mod 3.958” Surf 4,569’ 2-3/8" Velocity String (Nov-2016) 4.7#/L-80/8Rnd EUE 1.995” Surf 5,106’ JEWELRY DETAIL No Depth Length ID OD Item 1 2,382 3.858” 5.93” Baker Chemical Injection Nipple 2 4,569' 10’ ZXP Liner Packer w/ 15' Tieback Extension 3 4,609' 8’ Flex Lock Liner Hanger 4 5,040’ 4’ 1.875” 3.248” HAL XD Sliding Sleeve (X nipple at top) Down to close operation. OPEN as of 6/18/20. 5 5,089’ 2’ 1.921” 2.985” Ratch Latch w/ seal assembly 6 5,090’ 3’ 1.905” 3.75” WL Set Perma-Series Pkr 7 5,098’ 1’ 1.875” 2.72” 2-3/8” X Nipple 8 5,106’ 1’ 1.995” 3.52” WLEG 9 5733’ 12’ 3.375” Patch set 10/27/06 from 5733-5745’ MD 10 6,984' 4’ PAC Valve (stage cmt tool) Milled out 8/7/06 11 8090’ 1235’ n/a n/a CT cement plug from 8090’ – 9325’ (6/1/07) 12 8268’ 12’ 3.375” Patch set 10/25/06 from 8068-8280’ MD OPEN HOLE / CEMENT DETAIL 9-5/8" 12-1/4" hole, Cmt w/ 404 sks (180 bbls) 12 ppg Type 1 cmt with 30 bbls, 12 ppg cmt to surface. (with partial lost returns) 7" 8-1/2" hole, Cmt w/ 254 sks (111.7 bbls) 12.5 ppg type G Lead, plus 197 sks (40.9 bbls) 15.8 ppg type G Tail. Bump plug, 15 bbls contaminated with 5 bbls cmt to surface, 100% returns, floats held. 4-1/2" 7" hole, Cmt with 119 bbls 13.0 ppg. Lost circ w/83 bbls cmt displaced. PAC valve opened and immediately closed. Perfed 5,735' - 5,737' and squeezed 43 bbls 13.0 ppg Lead followed by 10 bbls 15.8 ppg Tail. 7.6 bbls cmt returns to surface. 8/25/06 CBL shows ToC at 7850’ MD. Remedial cement job shows BoC at 5740’ MC with patchy cement up to 4695’ MD Fill tagged at 5040’ SLMD on 6/16/21 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: Capstring Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 9,600 feet 7,532 feet true vertical 7,987 feet see schematic feet Effective Depth measured 8,090 feet 4,569; 5,090 feet true vertical 6,478 feet 3,028; 3,498 feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic 4-1/2" 12.6# / L-80 4,569' MD 4,569' TVD Tubing (size, grade, measured and true vertical depth)2-3/8" 4.7# / L-80 5,106' MD 3,513' TVD ZXP Liner Pkr; 4,569' MD 3,028' TVD Packers and SSSV (type, measured and true vertical depth)WL Pkr; N/A 5,090' MD 3,498' TVD N/A; N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Taylor Wellman 777-8449 Contact Name:Ryan Rupert Authorized Title:Operations Manager Contact Email: Contact Phone:777-8503 WINJ WAG 121 Water-Bbl MD 91' 1,630' 9,595' 0 Oil-Bbl measured true vertical Packer 4-1/2" 3,219' measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Ninilchik Field / Beluga-Tyonek GasN/A measured TVD Tubing Pressure 6157 Ninilchik Unit Susan Dionne 5 N/A FEE-CIRI; C-061505 4,788' Plugs Junk STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 206-088 50-133-20562-00-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 2. Operator Name:Hilcorp Alaska, LLC 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 321-165 35 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 0 Authorized Signature with date: Authorized Name: 0 Casing Pressure Liner 5,026' 0 7,982' 0 Representative Daily Average Production or Injection Data 91' 1,630' 4,788' Conductor Surface Intermediate Production 7,500psi Casing Structural 20" 9-5/8" 7" Length 7,240psi 5,750psi Collapse 1,500psi 3,090psi 5,410psi yan.rupert@hilcorp.co Senior Engineer:Senior Res. Engineer: 8,930psi Burst 3,060psi91' 1,298' t Fra O 6. A G L PG , R g Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Meredith Guhl at 4:06 pm, May 17, 2021 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.05.17 15:55:26 -08'00' Taylor Wellman (2143) RBDMS HEW 5/18/2021 BJM 9/27/21 SFD 5/20/2021DSR-5/17/21 Rig Start Date End Date E-Line 4/21/21 4/27/21 04/27/2021 - Tuesday Sign in. PTW and JSA. Spot and rig up equipment. PT to 250 psi low and 2,500 psi high. RIH w/ 1-11/16" x 10' 6 spf, 60 deg phase and tie into CCL log sent from town. Run correlation log and send to town. Get ok to perf from 5,128' to 5,138' w/54.7 psi. Spot and fire gun at 54.7 psi. After 5 min - 55 psi, 10 min - 55.3 psi and 15 min - 56 psi with zero rate. POOH. All shots fired. Got compressor going. RIH w/ 1-11/16" x 10' 6 spf, 60 deg phase and tie into CCL log sent from town. Run correlation log and send to town. Get ok to perf from 5,152' to 5,162'. Spot and fire gun with 59 psi/190MCF, 5 min - 58 psi, 10 min - 57 psi and 15 min - 57 psi/180MCF. POOH. All shots fired. RIH w/ 1-11/16" x 10' 6 spf, 60 deg phase and tie into CCL log sent from town. Gun set down at 5215'. Pull up and was real sticky. Was afraid strip gun was bent or det cord was cut. Call town and discussed. Decision made to POOH and check gun. Gun didn't look to bad but town decided to rig down. Rig down off well and rig down equipment. Secure well and turn over to field. 04/21/2021 - Wednesday Leave shop. Travel to location w/ units. Meet with company rep. Aquire permits. Safety meeting. RU SL unit. Stab lubricator on well. PT SL PCE. Open tree valves. RIH w/ 13' X 1¼" weight bar / 1¼" jars / 1¼" short spangs / 1.5" TEL / 1.75" gauge ring. Tag tbg bottom @ 5,086' SLD. Shear tool. TEL won't travel back down hole. POOH. Tag fill @ 5,276' SLD. POOH to tubing end. Tag tubing end @ 5,086' SLD. Btm tool 1' below at 5,087' SLD. RIH w/ 13' X 1¼" weight bar / 1¼" jars / 1/¼" short spangs / 12' X 1 11/16" W/L weight bar. Tag bottom @ 5,276' SLD. POOH. This puts tubing tail at 5,106' ELMD and tag depth at 5,295' ELMD. RIH w/ 13' X 1¼" weight bar / 1¼" jars / 1¼" short spangs / tandem EMR's. Tag bottom. Wait 5 mins for gauge stabilization. POOH @ 30ft/min to 5000ft. POOH 100ft/min to surface. Well flowing at 60psi FTP and 175mcfd total. DL EMR's. Data Good. RD SL. RTB. Daily Operations: 04/19/2021 - Monday Pulled 3/8" cap string form 5100' MD. Full recovery. Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name SD-05 50-133-20562-00-00 206-088 o perf from 5,128' to 5,138' w Pulled 3/8" cap string form 5100' MD. Full recovery. o perf from 5,152' to 5,162' Tag bottom @ 5,276' SLD. P fire gun a _____________________________________________________________________________________ Updated by CRR 05-13-21 SCHEMATIC Cook Inlet Basin, Alaska Middle Ground Shoal Last Completed: 02-28-1992 Oil Well ->Water injector -> Gas producer for Platform Ninilchik Unit Susan Dionne 05 PTD: 206-088 API: 50-133-20562-00-00 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Perf’d Status BLG-120 5,128’ 5,138’ 3,534’ 3,543’ 10 4/27/21 Open 5,152’ 5,162’ 3,556’ 3,566’ 10 4/27/21 Open 5,163’ 5,173’ 3,567’ 3,576’ 10 2/21/13 Open BLG-134 5,247’ 5,257’ 3,647’ 3,656’ 10 2/21/13 Open BLG-135 5,317' 5,343' 3,714' 3,739' 26' 6/7/07 Open Tyonek Sqz Holes 5,735' 5,737' 4,123' 4,125' 2' 8/8/06 Patched (10/27/06) & Cement isolated (6/1/07) T-65 8,270' 8,276' 6,657' 6,663' 6' 10/3/06 Patched (10/25/06) & Cement isolated (6/1/07) T-83 8,508' 8,524' 6,895' 6,911' 16' 10/3/06 Cmt isolated (07’) T-140 9,263' 9,289' 7,650' 7,676' 26' 10/3/06 Cmt isolated (07’) Zon BLG-1 BLG-1 BLG-1 Tyon Sqz Ho T-6 T-8 T-14 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20" Conductor 133# / K-55 / PE 18.73” Surf 91' 9-5/8" Surface 40# / L-80 / BTC 8.835” Surf 1,630' 7" Intermediate 26# / L-80 / BTC 6.276” Surf 4,788' 4-1/2" Liner 12.6# / L-80 / Hydril 563 3.958” 4,569' 9,595' TUBING DETAIL 4-1/2" Tubing 12.6#/L-80/Buttress Mod 3.958” Surf 4,569’ 2-3/8" Velocity String (Nov-2016) 4.7#/L-80/8Rnd EUE 1.995” Surf 5,106’ JEWELRY DETAIL No Depth Length ID OD Item 1 2,382 3.858” 5.93” Baker Chemical Injection Nipple 2 4,569' 10’ ZXP Liner Packer w/ 15' Tieback Extension 3 4,609' 8’ Flex Lock Liner Hanger 4 5,040’ 4’ 1.875” 3.248” HAL XD Sliding Sleeve (X nipple at top) Down to close operation. OPEN as of 6/18/20. 5 5,089’ 2’ 1.921” 2.985” Ratch Latch w/ seal assembly 6 5,090’ 3’ 1.905” 3.75” WL Set Perma-Series Pkr 7 5,098’ 1’ 1.875” 2.72” 2-3/8” X Nipple 8 5,106’ 1’ 1.995” 3.52” WLEG 9 5733’ 12’ 3.375” Patch set 10/27/06 from 5733-5745’ MD 10 6,984' 4’ PAC Valve (stage cmt tool) Milled out 8/7/06 11 8090’ 1235’ n/a n/a CT cement plug from 8090’ – 9325’ (6/1/07) 12 8268’ 12’ 3.375” Patch set 10/25/06 from 8068-8280’ MD OPEN HOLE / CEMENT DETAIL 9-5/8" 12-1/4" hole, Cmt w/ 404 sks (180 bbls) 12 ppg Type 1 cmt with 30 bbls, 12 ppg cmt to surface. (with partial lost returns) 7" 8-1/2" hole, Cmt w/ 254 sks (111.7 bbls) 12.5 ppg type G Lead, plus 197 sks (40.9 bbls) 15.8 ppg type G Tail. Bump plug, 15 bbls contaminated with 5 bbls cmt to surface, 100% returns, floats held. 4-1/2" 7" hole, Cmt with 119 bbls 13.0 ppg. Lost circ w/83 bbls cmt displaced. PAC valve opened and immediately closed. Perfed 5,735' - 5,737' and squeezed 43 bbls 13.0 ppg Lead followed by 10 bbls 15.8 ppg Tail. 7.6 bbls cmt returns to surface. 8/25/06 CBL shows ToC at 7850’ MD. Remedial cement job shows BoC at 5740’ MC with patchy cement up to 4695’ MD Fill tagged at 5215’ ELMD on 4/27/21 (sticky) 120 5,128’ 5,138’ 3,534’3,543’10 4/27/21 Open 5,152’ 5,162’ 3,556’3,566’10 4/27/21 Open BLG-1 ,,,,//p 1.Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: __Cap string______ 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6.API Number: 7.If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 9,600'see schematic Casing Collapse Structural Conductor 1,500 psi Surface 3,090 psi Intermediate 5,410 psi Production Liner 7,500 psi Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15.W ell Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Ryan Rupert Operations Manager Contact Email: Contact Phone: 777-8503 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng ~1263 psi see schematic ZXP Liner Packer; WL Pkr / SSSV - N/A Packer 4,569' (MD) 3,028' (TVD); 5,090' MD 3,498' TVD / SSSV - N/A Perforation Depth TVD (ft): COMMISSION USE ONLY Authorized Name: 8,930 psi Tubing Grade:Tubing MD (ft): ryan.rupert@hilcorp.com STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEE-CIRI, C-061505 206-088 50-133-20562-00-00 Ninilchik Unit Susan Dionne 5 Ninilchik Field / Beluga-Tyonek Gas Length Size CO 701C Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY 7,987'8,090'6,478' 12.6# / L-80 TVD Burst 4,569' MD 7,240 psi - 5,750 psi 91' 1,298' 3,219' 91' 1,630' 20" 9-5/8" 91' 7"4,788' 1,630' Perforation Depth MD (ft): 4,788' See Attached Schematic 4-1/2" See Attached Schematic Tubing Size: Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: May 31, 2021 9,595'5,026' 4-1/2" 7,982' m n P 66 t _ c Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Meredith Guhl at 4:02 pm, May 17, 2021 321-243 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.05.17 11:33:03 -08'00' Taylor Wellman (2143) 10-404 DSR-5/17/21 X ; FEE-Private (surface) DLB DLB 05/18/2021BJM 6/1/21 Separate sundry required for capstring installation. dts 6/1/2021 6/1/21Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2021.06.01 11:57:07 -08'00' RBDMS HEW 6/2/2021 Perf Add Well: SD-05 Date: 5/14/2021 Well Name:SD-05 API Number:50-133-20562-00-00 Current Status:Gas Producer Leg:N/A Regulatory Contact:Donna Ambruz 777-8305 Permit to Drill Number:206-088 First Call Engineer:Ryan Rupert (907) 777-8503 (O)(907) 301-1736 (C) Second Call Engineer:Ted Kramer (907) 777-8420 (O)(985) 867-0665 (C) Maximum Expected BHP:~ 1622 psi @ 3,588’ TVD Using a 0.452 gradient to BEL-132 Max. Potential Surface Pressure:~ 1263 psi Using Max BHP minus 0.1 psi/ft. gas gradient to surface). Well Summary SD-05was alow gas / high volume water producer (100bwpd+)until perfs were added in April-2021. These perfs didn’t add any gas, and may have added some water. The well has been SI for low flow since. The plan for this project is to perforate remaining Beluga intervals below the 2-3/8” velocity string in an attempt to increase production. The well may also need its capstring reinstalled, TBD. Notes Regarding Wellbore Condition x Min ID = 1.875” at 5040’ MD and 5098’ MD (2-3/8” X nipples) x Max inclination = 63 degrees 1434’ MD x Drifts o 4/27/21: EL tagged at 5215’ MD with a 10’ x 1-11/16” strip gun (appears fill had come in) o 4/21/21: SL tagged at 5295’ ELMD o 5/11/20: 1.85” gauge ring tags at 5322’ MD o 3/23/18: SL tags at 5330’ MD with a 1.75” x 5’ DD bailer (full of sand) o 2/22/17: EL PLT. 1-11/16” x 44’. Had to SI well to get past 1200’ MD. o Nov-2016: 2-7/8” velocity string installed Perf Add Well: SD-05 Date: 5/14/2021 EL Perforating 1. MIRU EL 2. PT BOP equipment to 250 psi Low / 2,500 psi High. 3. Rig up CCL tool and drift well for upcoming strip guns. 4. RIH and obtain a light tag, then tie tag depth into the tubing tail (5106’ ELMD) 5. MU 1-11/16” strip guns per below 6. RIH and perforate the sands listed in the table below: Consult with OE for what WHP to use. Some interval(s) may be shot flowing. Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. a.Use Gamma/CCL to correlate. b. Record initial and 5/10/15 minute tubing pressures after firing c. Consult with RE/Geo between each perf interval: i. Anthony McConkey: RE - 529-6199 ii. Matthew Petrowsky: Geo – 814-421-6753 7. RD E-Line Unit and turn well over to production. Capstring Procedure (CONTINGENCY): 1. MIRU Cap String Truck, PT lubricator to 2,500 psi Hi 250 Low. 2. Install wellhead packoff. 3. PU 3/8” capillary string. RIH and set @ ±5,100’ MD 4. Set spool of remaining line near well. 5. Rig down Cap String Truck. 6. Turn well over to production. EL zone shutoff Procedure (CONTINGENCY): 1. MIRU EL 2. PT BOP equipment to 250 psi Low / 2,500 psi High. 3. Batch up cement and rig up dump bailer 4. RIH and dump bail cement as needed to shutoff water production from lower zones 5. RDMO EL Attachments: 1. Proposed Schematic Sand MD Top MD Bottom TVD Top TVD Bottom Total Footage (MD) BEL 132 ±5,182'±5,185'±3,585'±3,588'3' BEL 133 ±5,202'±5,218'±3,604'±5,218'16' Submit another sundry if capstring is required. BJM _____________________________________________________________________________________ Updated by CRR 05-13-21 PROPOSED SCHEMATIC Cook Inlet Basin, Alaska Middle Ground Shoal Last Completed: 02-28-1992 Oil Well ->Water injector -> Gas producer for Platform Ninilchik Unit Susan Dionne 05 PTD: 206-088 API: 50-133-20562-00-00 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Perf’d Status BLG-120 5,128’5,138’3,534’3,543’10 4/27/21 Open 5,152’5,162’3,556’3,566’10 4/27/21 Open 5,163’5,173’3,567’3,576’10 2/21/13 Open BEL 132 ±5,182'±5,185'±3,585'±3,588'3'TBD Proposed BEL 133 ±5,202'±5,218'±3,604'±3,218'16'TBD Proposed BLG-134 5,247’5,257’3,647’3,656’10 2/21/13 Open BLG-135 5,317'5,343'3,714'3,739'26'6/7/07 Open Tyonek Sqz Holes 5,735'5,737'4,123'4,125'2' 8/8/06 Patched (10/27/06) & Cement isolated (6/1/07) T-65 8,270'8,276'6,657'6,663'6' 10/3/06 Patched (10/25/06) & Cement isolated (6/1/07) T-83 8,508'8,524'6,895'6,911'16'10/3/06 Cmt isolated (07’) T-140 9,263'9,289'7,650'7,676'26'10/3/06 Cmt isolated (07’) Zon BLG-1 BEL 1 BEL 1 BLG-1 BLG-1 Tyon Sqz Ho T-6 T-8 T-14 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 133# / K-55 / PE 18.73”Surf 91' 9-5/8"Surface 40# / L-80 / BTC 8.835”Surf 1,630' 7"Intermediate 26# / L-80 / BTC 6.276”Surf 4,788' 4-1/2"Liner 12.6# / L-80 / Hydril 563 3.958”4,569'9,595' TUBING DETAIL 4-1/2"Tubing 12.6#/L-80/Buttress Mod 3.958”Surf 4,569’ 2-3/8"Velocity String (Nov-2016)4.7#/L-80/8Rnd EUE 1.995”Surf 5,106’ JEWELRY DETAIL No Depth Length ID OD Item 1 2,382 3.858”5.93”Baker Chemical Injection Nipple 2 4,569'10’ZXP Liner Packer w/ 15' Tieback Extension 3 4,609'8’Flex Lock Liner Hanger 4 5,040’ 4’ 1.875”3.248”HAL XD Sliding Sleeve (X nipple at top)Down to close operation.OPEN as of 6/18/20. 5 5,089’2’1.921”2.985”Ratch Latch w/ seal assembly 6 5,090’3’1.905”3.75”WL Set Perma-Series Pkr 7 5,098’1’1.875”2.72”2-3/8” X Nipple 8 5,106’1’1.995”3.52”WLEG 9 5733’12’3.375”Patch set 10/27/06 from 5733-5745’ MD 10 6,984'4’PAC Valve (stage cmt tool) Milled out 8/7/06 11 8090’1235’n/a n/a CT cement plug from 8090’–9325’ (6/1/07) 12 8268’12’3.375”Patch set 10/25/06 from 8068-8280’ MD OPEN HOLE / CEMENT DETAIL 9-5/8"12-1/4" hole, Cmt w/ 404 sks (180 bbls) 12 ppg Type 1 cmt with 30 bbls, 12 ppg cmt to surface. (with partial lost returns) 7" 8-1/2" hole, Cmt w/ 254 sks (111.7 bbls) 12.5 ppg type G Lead, plus 197 sks (40.9 bbls) 15.8 ppg type G Tail. Bump plug, 15 bbls contaminated with 5 bbls cmt to surface, 100% returns, floats held. 4-1/2" 7" hole, Cmt with 119 bbls 13.0 ppg. Lost circ w/83 bbls cmt displaced. PAC valve opened and immediately closed. Perfed 5,735'- 5,737' and squeezed 43 bbls 13.0 ppg Lead followed by 10 bbls 15.8 ppg Tail. 7.6 bbls cmt returns to surface. 8/25/06 CBL shows ToC at 7850’ MD. Remedial cement job shows BoC at 5740’ MC with patchy cement up to 4695’ MD Fill tagged at 5215’ ELMD on 4/27/21 (sticky) Samuel Gebert Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 05/06/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL SD-05 (PTD 206-088) PERFORATING RECORD 04/27/2021 Please include current contact information if different from above. PTD: 2060880 E-Set: 35103 Received by the AOGCC 05/06/2021 05/06/2021 1.Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: __Cap string______ 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6.API Number: 7.If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 9,600' Casing Collapse Structural Conductor 1,500 psi Surface 3,090 psi Intermediate 5,410 psi Production Liner 7,500 psi Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15.W ell Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Ryan Rupert Operations Manager Contact Email: Contact Phone: 777-8503 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by:COMMISSIONER THE COMMISSION Date: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng see ryan.rupert@hilcorp.com 7,987'8,090'6,478'~336 psi see schematic ZXP Liner Packer; WL Pkr / SSSV - N/A Packer 4,569' (MD) 3,028' (TVD); 5,090' MD 3,498' TVD / SSSV - N/A Perforation Depth TVD (ft):Tubing Size: COMMISSION USE ONLY Authorized Name: 8,930 psi Tubing Grade:Tubing MD (ft): See Attached Schematic STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEE-CIRI, C-061505 206-088 50-133-20562-00-00 Ninilchik Unit Susan Dionne 5 Ninilchik Field / Beluga-Tyonek Gas Length Size CO 701C Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY 12.6# / L-80 TVD Burst 4,569' MD 7,240 psi - 5,750 psi 91' 1,298' 3,219' 91' 1,630' 20" 9-5/8" 91' 7"4,788' 1,630' Perforation Depth MD (ft): 4,788' See Attached Schematic 4-1/2" Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: April 15, 2021 9,595'5,026' 4-1/2" 7,982' m n P 66 t _ c Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 3:46 pm, Apr 06, 2021 321-165 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.03.31 15:32:32 -08'00' Taylor Wellman (2143) DSR-4/6/21SFD 4/6/2021BJM 4/9/21 10-404ion Required? Yes Comm 4/12/21 dts 4/9/2021 JLC 4/12/2021 RBDMS HEW 4/12/2021 Perf Add Well: SD-05 Date: 3/31/2021 Well Name:SD-05 API Number:50-133-20562-00-00 Current Status:Gas Producer Leg:N/A Regulatory Contact:Donna Ambruz 777-8305 Permit to Drill Number:206-088 First Call Engineer:Ryan Rupert (907) 777-8503 (O)(907) 301-1736 (C) Second Call Engineer:Ted Kramer (907) 777-8420 (O)(985) 867-0665 (C) Maximum Expected BHP:~ 683 psi @ 3,476’ TVD (2020 RFT in BEL-120 from Kal-07) Max. Potential Surface Pressure:~ 336 psi Using Max BHP minus 0.1 psi/ft. gas gradient to surface). Well Summary SD-05 has been a consistent producer since 2006. It has always produced water, and is now down to ~125mcfd and up to 50bwpd. The plan for this project is to perforate remaining Beluga intervals below the 2-3/8” velocity string in an attempt to increase production. Notes Regarding Wellbore Condition x Min ID = 1.875” at 5040’ MD and 5098’ MD (2-3/8” X nipples) x Max inclination = 63 degrees 1434’ MD x Drifts o 5/11/20: 1.85” gauge ring tags at 5322’ MD o 3/23/18: SL tags at 5330’ MD with a 1.75” x 5’ DD bailer (full of sand) o 2/22/17: EL PLT. 1-11/16” x 44’. Had to SI well to get past 1200’ MD. Tagged at 5300’ MD (appeared to have flow from below this, though) Nov-2016: 2-7/8” velocity string installed o 8/11/14: SL bailed 4’ of sand down to 5304’ MD o 2/16/13: 3.68” gauge ring tags top of patch at 5733’ MD Capstring Removal (pre-sundry) 1. MIRU Cap String Truck, PT lubricator to 2,500 psi Hi 250 Low. 2. Pull 3/8” capillary string from well 3. Rig down Cap String Truck. 4. Turn well over to production. Slickline (pre-sundry) 5. MIRU SL 6. PT to 250 low / 2500 high 7. D&T with 1.75” gauge centralizer or gauge ring to PBTD 8. Drift to PBTD to mimic a 25’ x 1-11/16” Strip gun: (Target 5600’ MD, if possible) 9. Perform flowing memory P/T survey from PBTD to surface 10. RDMO SL o perforate remaining Beluga intervals b Perf Add Well: SD-05 Date: 3/31/2021 EL Perforating (will require an approved sundry first) 1. MIRU EL 2. PT BOP equipment to 250 psi Low / 2,500 psi High. 3. Rig up 1-11/16” strip guns 4. RIH and perforate the sands listed in the table below: Consult with OE for what WHP to use. Some interval(s) may be shot flowing. Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. a.Use Gamma/CCL to correlate. b. Record initial and 5/10/15 minute tubing pressures after firing c. Consult with RE/Geo between each perf interval: i. Anthony McConkey: RE - 529-6199 ii. Matthew Petrowsky: Geo – 814-421-6753 5. RD E-Line Unit and turn well over to production. Capstring Procedure: 1. MIRU Cap String Truck, PT lubricator to 2,500 psi Hi 250 Low. 2. Install wellhead packoff. 3. PU 3/8” capillary string. RIH and set @ ±5,100’ MD 4. Set spool of remaining line near well. 5. Rig down Cap String Truck. 6. Turn well over to production. Attachments: 1. Current schematic 2. Proposed Schematic Sand MD Top MD Bottom TVD Top TVD Bottom Total Footage (MD) Expected Pressure BEL 120 ±5,114’±5,169’±3,520'±3,573'55'683 (RFT from Kal 7) BEL 134U ±5,240’±5,253’±3,640'±3,652'13’273 (RFT from Kal 6) BEL 134L ±5,259’±5,270’±3,658'±3,669'11’273 (RFT from Kal 6) BEL 135 ±5,316’±5,359’±3,713'±3,754'43'356 (RFT from Kal 4) TY 2 ±5,532’±5,541’±3,922'±3,931'9’612 (RFT from Kal 7) _____________________________________________________________________________________ Updated by CRR 03-30-21 SCHEMATIC Cook Inlet Basin, Alaska Middle Ground Shoal Last Completed: 02-28-1992 Oil Well ->Water injector -> Gas producer for Platform Well: Susan Dionne 05 PTD: 206-088 API: 50-133-20562-00-00 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Perf’d Status BLG-120 5,163’5,173’3,567’3,576’10 2/21/13 Open BLG-134 5,247’5,257’3,647’3,656’10 2/21/13 Open BLG-135 5,317'5,343'3,714'3,739'26'6/7/07 Open Tyonek Sqz Holes 5,735'5,737'4,123'4,125'2' 8/8/06 Patched (10/27/06) & Cement isolated (6/1/07) T-65 8,270'8,276'6,657'6,663'6' 10/3/06 Patched (10/25/06) & Cement isolated (6/1/07) T-83 8,508'8,524'6,895'6,911'16'10/3/06 Cmt isolated (07’) T-140 9,263'9,289'7,650'7,676'26'10/3/06 Cmt isolated (07’) Zon BLG-1 BLG-1 BLG-1 Tyon Sqz Ho T-6 T-8 T-14 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 133# / K-55 / PE 18.73”Surf 91' 9-5/8"Surface 40# / L-80 / BTC 8.835”Surf 1,630' 7"Intermediate 26# / L-80 / BTC 6.276”Surf 4,788' 4-1/2"Liner 12.6# / L-80 / Hydril 563 3.958”4,569'9,595' TUBING DETAIL 4-1/2"Tubing 12.6#/L-80/Buttress Mod 3.958”Surf 4,569’ 2-3/8"Velocity String (Nov-2016)4.7#/L-80/8Rnd EUE 1.995”Surf 5,106’ JEWELRY DETAIL No Depth Length ID OD Item 1 2,382 3.858”5.93”Baker Chemical Injection Nipple 2 4,569'10’ZXP Liner Packer w/ 15' Tieback Extension 3 4,609'8’Flex Lock Liner Hanger 4 5,040’ 4’ 1.875”3.248”HAL XD Sliding Sleeve (X nipple at top) Down to close operation.OPEN as of 6/18/20. 5 5,089’2’1.921”2.985”Ratch Latch w/ seal assembly 6 5,090’3’1.905”3.75”WL Set Perma-Series Pkr 7 5,098’1’1.875”2.72”2-3/8” X Nipple 8 5,106’1’1.995”3.52”WLEG 9 5733’12’3.375”Patch set 10/27/06 from 5733-5745’ MD 10 6,984'4’PAC Valve (stage cmt tool) Milled out 8/7/06 11 8090’1235’n/a n/a CT cement plug from 8090’ – 9325’ (6/1/07) 12 8268’12’3.375”Patch set 10/25/06 from 8068-8280’ MD OPEN HOLE / CEMENT DETAIL 9-5/8"12-1/4" hole, Cmt w/ 404 sks (180 bbls) 12 ppg Type 1 cmt with 30 bbls, 12 ppg cmt to surface. (with partial lost returns) 7" 8-1/2" hole, Cmt w/ 254 sks (111.7 bbls) 12.5 ppg type G Lead, plus 197 sks (40.9 bbls) 15.8 ppg type G Tail. Bump plug, 15 bbls contaminated with 5 bbls cmt to surface, 100% returns, floats held. 4-1/2" 7" hole, Cmt with 119 bbls 13.0 ppg. Lost circ w/83 bbls cmt displaced. PAC valve opened and immediately closed. Perfed 5,735'- 5,737' and squeezed 43 bbls 13.0 ppg Lead followed by 10 bbls 15.8 ppg Tail. 7.6 bbls cmt returns to surface.8/25/06 CBL shows ToC at 7850’ MD. Remedial cement job shows BoC at 5740’ MC with patchy cement up to 4695’ MD 3/8” Capillary String Installed 8/14/20 Top Bottom MD 0’ 5,100’ TVD 0’ 3,507’ _____________________________________________________________________________________ Updated by CRR 03-31-21 PROPOSED SCHEMATIC Cook Inlet Basin, Alaska Middle Ground Shoal Last Completed: 02-28-1992 Oil Well ->Water injector -> Gas producer for Platform Well: Susan Dionne 05 PTD: 206-088 API: 50-133-20562-00-00 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD)FT Date Perf’d Status Adperf / Reperf per sundry BLG-120 5,163’5,173’3,567’3,576’10 2/21/13 Open BLG-134 5,247’5,257’3,647’3,656’10 2/21/13 Open BLG-135 5,317'5,343'3,714'3,739'26'6/7/07 Open Tyonek Sqz Holes 5,735'5,737'4,123'4,125'2' 8/8/06 Patched (10/27/06) & Cement isolated (6/1/07) T-65 8,270'8,276'6,657'6,663'6' 10/3/06 Patched (10/25/06) & Cement isolated (6/1/07) T-83 8,508'8,524'6,895'6,911'16'10/3/06 Cmt isolated (07’) T-140 9,263'9,289'7,650'7,676'26'10/3/06 Cmt isolated (07’) Zon BLG-1 BLG-1 BLG-1 Tyon Sqz Ho T-6 T-8 T-14 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm 20"Conductor 133# / K-55 / PE 18.73”Surf 91' 9-5/8"Surface 40# / L-80 / BTC 8.835”Surf 1,630' 7"Intermediate 26# / L-80 / BTC 6.276”Surf 4,788' 4-1/2"Liner 12.6# / L-80 / Hydril 563 3.958”4,569'9,595' TUBING DETAIL 4-1/2"Tubing 12.6#/L-80/Buttress Mod 3.958”Surf 4,569’ 2-3/8"Velocity String (Nov-2016)4.7#/L-80/8Rnd EUE 1.995”Surf 5,106’ JEWELRY DETAIL No Depth Length ID OD Item 1 2,382 3.858”5.93”Baker Chemical Injection Nipple 2 4,569'10’ZXP Liner Packer w/ 15' Tieback Extension 3 4,609'8’Flex Lock Liner Hanger 4 5,040’ 4’ 1.875”3.248”HAL XD Sliding Sleeve (X nipple at top) Down to close operation.OPEN as of 6/18/20. 5 5,089’2’1.921”2.985”Ratch Latch w/ seal assembly 6 5,090’3’1.905”3.75”WL Set Perma-Series Pkr 7 5,098’1’1.875”2.72”2-3/8” X Nipple 8 5,106’1’1.995”3.52”WLEG 9 5733’12’3.375”Patch set 10/27/06 from 5733-5745’ MD 10 6,984'4’PAC Valve (stage cmt tool) Milled out 8/7/06 11 8090’1235’n/a n/a CT cement plug from 8090’ – 9325’ (6/1/07) 12 8268’12’3.375”Patch set 10/25/06 from 8068-8280’ MD OPEN HOLE / CEMENT DETAIL 9-5/8"12-1/4" hole, Cmt w/ 404 sks (180 bbls) 12 ppg Type 1 cmt with 30 bbls, 12 ppg cmt to surface. (with partial lost returns) 7" 8-1/2" hole, Cmt w/ 254 sks (111.7 bbls) 12.5 ppg type G Lead, plus 197 sks (40.9 bbls) 15.8 ppg type G Tail. Bump plug, 15 bbls contaminated with 5 bbls cmt to surface, 100% returns, floats held. 4-1/2" 7" hole, Cmt with 119 bbls 13.0 ppg. Lost circ w/83 bbls cmt displaced. PAC valve opened and immediately closed. Perfed 5,735'- 5,737' and squeezed 43 bbls 13.0 ppg Lead followed by 10 bbls 15.8 ppg Tail. 7.6 bbls cmt returns to surface.8/25/06 CBL shows ToC at 7850’ MD. Remedial cement job shows BoC at 5740’ MC with patchy cement up to 4695’ MD 3/8” Capillary String To be reinstalled Top Bottom MD 0’ 5,100’ TVD 0’ 3,507’ 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: Install Capstring Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 9,600 feet 7,532 feet true vertical 7,987 feet N/A feet Effective Depth measured 7,532 feet 4,569; 5,090 feet true vertical 5,920 feet 3,028; 3,498 feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic 4-1/2" 12.6# / L-80 4,569' MD 4,569' TVD Tubing (size, grade, measured and true vertical depth)2-3/8" 4.7# / L-80 5,106' MD 3,513' TVD ZXP Liner Pkr; 4,569' MD 3,028' TVD Packers and SSSV (type, measured and true vertical depth)WL Pkr; N/A 5,090' MD 3,498' TVD N/A; N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Taylor Wellman 777-8449 Contact Name:Mike Quick Authorized Title:Operations Manager Contact Email: Contact Phone:777-8442 mquick@hilcorp.com Senior Engineer:Senior Res. Engineer: 8,930psi Burst 3,060psi91' 1,298' 7,240psi 5,750psi Collapse 1,500psi 3,090psi 5,410psi 7,500psi Casing Structural 20" 9-5/8" 7" Length 91' 1,630' 4,788' Conductor Surface Intermediate Production Authorized Signature with date: Authorized Name: 0 Casing Pressure Liner 5,026' 793 7,982' 0 Representative Daily Average Production or Injection Data 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 320-300 65 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 4 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 206-088 50-133-20562-00-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 2. Operator Name:Hilcorp Alaska, LLC 6593 Ninilchik Unit S Dionne 5 N/A FEE-CIRI; C-061505 4,788' Plugs Junk measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Ninilchik Field / Beluga-Tyonek GasN/A measured TVD Tubing PressureOil-Bbl measured true vertical Packer 4-1/2" 3,219' WINJ WAG 702 Water-Bbl MD 91' 1,630' 9,595' 80 t Fra O 6. A G L PG , R g Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 3:18 pm, Sep 11, 2020 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.09.11 14:02:28 -08'00' Taylor Wellman SFD 9/14/2020 gls 10/21/20 DSR-9/15/2020 RBDMS HEW 9/14/2020 320-300 Install Capstringg Rig Start Date End Date Cap String 8/14/20 8/14/20 08/14/2020 - Friday Install 3/8" CAP string. Set at 5,100' MD. Foot valve crack PSI set for 2,700#. Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name SD-05 50-133-20562-00-00 206-088 _____________________________________________________________________________________ Updated by DMA 08-28-20 SCHEMATIC Cook Inlet Basin, Alaska Middle Ground Shoal Last Completed: 02-28-1992 Oil Well ->Water injector -> Gas producer for Platform Ninilchik Field Well #: Susan Dionne 05 Last Completed: 8/7/2006 PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status BLG-130 5,163’ 5,173’ 3,567’ 3,576’ 10 2/21/13 Open BLG-130 5,251’ 5,253’ 3,650’ 3,652’ 10 2/20/13 Open BLG-132 5,247’ 5,257’ 3,647’ 3,656’ 10 2/21/13 Open BLG-135 5,317' 5,343' 3,714' 3,739' 26' 6/7/07 Open Tyonek 5,735' 5,737' 4,123' 4,125' 2' 10/26/06 Squeezed & Casing Patched T-65 8,270' 8,276' 6,657' 6,663' 6' 10/24/06 Squeezed & Casing Patched T-83 8,508' 8,524' 6,895' 6,911' 16' 5/31/08 Squeezed T-140 9,263' 9,289' 7,650' 7,676' 26' 5/31/08 Squeezed Zone BLG-130 BLG-130 BLG-132 BLG-135 Tyonek T-65 T-83 T-140 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm CMT Top 20" Conductor 133# / K-55 / PE 18.73” Surf 91' 9-5/8" Surface 40# / L-80 / BTC 8.835” Surf 1,630' 12ppg/ Surface 7" Intermediate 26# / L-80 / BTC 6.276” Surf 4,788' Surface 4-1/2" Liner 12.6# / L-80 / Hydril 563 3.958” 4,569' 9,595' TUBING DETAIL 4-1/2" Tubing 12.6#/L-80/Buttress Mod 3.958” Surf 4,569’ 2-3/8" Velocity String 4.7#/L-80/8Rnd EUE 1.995” Surf 5,106’ JEWELRY DETAIL No Depth Length ID OD Item 1 2,382 3.858” 5.93” Baker Chemical Injection Nipple 2 4,569' 9.55’ ZXP Liner Packer w/ 15' Tieback Extension 3 4,609' 7.97’ Flex Lock Liner Hanger 4 5,040’ 3.72’ 1.875” 3.248” HAL XD Sliding Sleeve (X nipple profile at top of sleeve) 5 5,089’ 1.53’ 1.921” 2.985” Ratch Latch w/ seal assembly 6 5,090’ 2.53’ 1.905” 3.75” WL Set Perma-Series Pkr 7 5,098’ 1.28’ 1.875” 2.72” 2-3/8” X Nipple 8 5,106’ 0.45’ 1.995” 3.52” WLEG 9 6,984' 4’ PAC Valve 10 9,467' Landing Collar 11 9,509' Float Collar 12 9,593' Float Shoe OPEN HOLE / CEMENT DETAIL 9-5/8" 12-1/4" hole, Cmt w/ 404 sks (180 bbls) 12 ppg Type 1 cmt with 30 bbls, 12 ppg cmt to surface. (with partial lost returns) 7" 8-1/2" hole, Cmt w/ 254 sks (111.7 bbls) 12.5 ppg type G Lead, plus 197 sks (40.9 bbls) 15.8 ppg type G Tail. Bump plug, 15 bbls contaminated with 5 bbls cmt to surface, 100% returns, floats held. 4-1/2" 7" hole, Cmt w/ 20 bbl 10.5 ppg spacer followed by 330 sks (118.6 bbls) 13.0 ppg 8,045' KB cmt top from CBL run 8/7/2006. Lost circ w/83 bbls cmt displaced. PAC valve opened and immediately closed. Perfed 5,735' - 5,737' (Owen 3-3/8" 6 spf) to cmt above 120 sks (43 bbls) 13.0 ppg Lead followed by 50 sks (10 bbls) 15.8 ppg Tail 7.6 bbls cmt returns to surface. INCLINATION DETAIL KOP @ 200' MD/TVD Build 5.0 deg/100' from 200-1434' MD Hold 61.5 deg from 1434-2700' MD Drop 2 deg/100' to 5900' MD Hold 1.0 deg from 5900' to TD at 9,600' MD Azimuth: 220.7 deg. Capillary String Proposed to Install Top Bottom MD 0’ 5,100’ TVD 0’ 3,507’ 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: Remove Plunger Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 9,600 feet 7,532 feet true vertical 7,987 feet N/A feet Effective Depth measured 7,532 feet 4,569; 5,090 feet true vertical 5,920 feet 3,028; 3,498 feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic 4-1/2" 12.6# / L-80 4,569' MD 4,569' TVD Tubing (size, grade, measured and true vertical depth)2-3/8" 4.7# / L-80 5,106' MD 3,513' TVD ZXP Liner Pkr; 4,569' MD 3,028' TVD Packers and SSSV (type, measured and true vertical depth)WL Pkr; N/A 5,090' MD 3,498' TVD N/A; N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Taylor Wellman 777-8449 Contact Name:Ted Kramer Authorized Title:Operations Manager Contact Email: Contact Phone:777-8420 tkramer@hilcorp.com Senior Engineer:Senior Res. Engineer: 8,930psi Burst 3,060psi91' 1,298' 7,240psi 5,750psi Collapse 1,500psi 3,090psi 5,410psi 7,500psi Casing Structural 20" 9-5/8" 7" Length 91' 1,630' 4,788' Conductor Surface Intermediate Production Authorized Signature with date: Authorized Name: 3 Casing Pressure Liner 5,026' 742 7,982' 0 Representative Daily Average Production or Injection Data 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. N/A 45 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 3 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 206-088 50-133-20562-00-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 2. Operator Name:Hilcorp Alaska, LLC 4083 Ninilchik Unit S Dionne 5 N/A FEE-CIRI; C-061505 4,788' Plugs Junk measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Ninilchik Field / Beluga-Tyonek GasN/A measured TVD Tubing PressureOil-Bbl measured true vertical Packer 4-1/2" 3,219' WINJ WAG 359 Water-Bbl MD 91' 1,630' 9,595' 96 t Fra O 6. A G L PG , R Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 9:17 am, Jul 16, 2020 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.07.15 17:01:29 -08'00' Taylor Wellman SFD 7/16/2020RBDMS HEW 7/16/2020 DSR-7/16/2020gls 8/28/20 Rig Start Date End Date 6/18/20 6/18/20 06/18/2020 - Thursday Pulled Plunger Lift and bumper spring. Shifted Sleeve Up (OPEN). Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name SD-05 50-133-20562-00-00 206-088 _____________________________________________________________________________________ Updated by DMA 07-07-20 SCHEMATIC Cook Inlet Basin, Alaska Middle Ground Shoal Last Completed: 02-28-1992 Oil Well ->Water injector -> Gas producer for Platform Ninilchik Field Well #: Susan Dionne 05 Last Completed: 8/7/2006 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm CMT Top 20" Conductor 133# / K-55 / PE 18.73” Surf 91' 9-5/8" Surface 40# / L-80 / BTC 8.835” Surf 1,630' 12ppg/ Surface 7" Intermediate 26# / L-80 / BTC 6.276” Surf 4,788' Surface 4-1/2" Liner 12.6# / L-80 / Hydril 563 3.958” 4,569' 9,595' TUBING DETAIL 4-1/2" Tubing 12.6#/L-80/Buttress Mod 3.958” Surf 4,569’ 2-3/8" Velocity String 4.7#/L-80/8Rnd EUE 1.995” Surf 5,106’ JEWELRY DETAIL No Depth Length ID OD Item 1 2,382 3.858” 5.93” Baker Chemical Injection Nipple 2 4,569' 9.55’ ZXP Liner Packer w/ 15' Tieback Extension 3 4,609' 7.97’ Flex Lock Liner Hanger 4 5,040’ 3.72’ 1.875” 3.248” HAL XA Sliding Sleeve (X nipple profile at top of sleeve) 5 5,089’ 1.53’ 1.921” 2.985” Ratch Latch w/ seal assembly 6 5,090’ 2.53’ 1.905” 3.75” WL Set Perma-Series Pkr 7 5,098’ 1.28’ 1.875” 2.72” 2-3/8” X Nipple 8 5,106’ 0.45’ 1.995” 3.52” WLEG 9 6,984' 4’ PAC Valve 10 9,467' Landing Collar 11 9,509' Float Collar 12 9,593' Float Shoe PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status BLG-130 5,163’ 5,173’ 3,567’ 3,576’ 10 2/21/13 Open BLG-130 5,251’ 5,253’ 3,650’ 3,652’ 10 2/20/13 Open BLG-132 5,247’ 5,257’ 3,647’ 3,656’ 10 2/21/13 Open BLG-135 5,317' 5,343' 3,714' 3,739' 26' 6/7/07 Open Tyonek 5,735' 5,737' 4,123' 4,125' 2' 10/26/06 Squeezed & Casing Patched T-65 8,270' 8,276' 6,657' 6,663' 6' 10/24/06 Squeezed & Casing Patched T-83 8,508' 8,524' 6,895' 6,911' 16' 5/31/08 Squeezed T-140 9,263' 9,289' 7,650' 7,676' 26' 5/31/08 Squeezed OPEN HOLE / CEMENT DETAIL 9-5/8" 12-1/4" hole, Cmt w/ 404 sks (180 bbls) 12 ppg Type 1 cmt with 30 bbls, 12 ppg cmt to surface. (with partial lost returns) 7" 8-1/2" hole, Cmt w/ 254 sks (111.7 bbls) 12.5 ppg type G Lead, plus 197 sks (40.9 bbls) 15.8 ppg type G Tail. Bump plug, 15 bbls contaminated with 5 bbls cmt to surface, 100% returns, floats held. 4-1/2" 7" hole, Cmt w/ 20 bbl 10.5 ppg spacer followed by 330 sks (118.6 bbls) 13.0 ppg 8,045' KB cmt top from CBL run 8/7/2006. Lost circ w/83 bbls cmt displaced. PAC valve opened and immediately closed. Perfed 5,735' - 5,737' (Owen 3-3/8" 6 spf) to cmt above 120 sks (43 bbls) 13.0 ppg Lead followed by 50 sks (10 bbls) 15.8 ppg Tail 7.6 bbls cmt returns to surface. INCLINATION DETAIL KOP @ 200' MD/TVD Build 5.0 deg/100' from 200-1434' MD Hold 61.5 deg from 1434-2700' MD Drop 2 deg/100' to 5900' MD Hold 1.0 deg from 5900' to TD at 9,600' MD Azimuth: 220.7 deg. 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Install Capstring 2.Operator Name:4.Current Well Class:5. Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6.API Number: 7.If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9. Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 9,600'N/A Casing Collapse Structural Conductor 1,500 psi Surface 3,090 psi Intermediate 5,410 psi Production Liner 7,500 psi Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): ZXP Liner Packer; WL Pkr / SSSV - N/A Packer 4,569' (MD) 3,028' (TVD); 5,090' MD / 3,498' TVD / SSSV - N/A 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Mike Quick Operations Manager Contact Email: Contact Phone: 777-8442 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng mquick@hilcorp.com 7,987'7,532'5,920'~450psi 7,532' Perforation Depth TVD (ft): Tubing Size: 2-3/8" COMMISSION USE ONLY Authorized Name: 8,930 psi Tubing Grade: 4.7# / L-80 Tubing MD (ft): 5,106' See Attached Schematic STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEE-CIRI, C-061505 206-088 50-133-20562-00-00 Ninilchik Unit S Dionne 5 Ninilchik Field / Beluga-Tyonek Gas Length Size CO 710A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY 12.6# / L-80 TVD Burst 4,569' MD 7,240 psi - 5,750 psi 91' 1,298' 3,219' 91' 1,630' 20" 9-5/8" 91' 7"4,788' 1,630' Perforation Depth MD (ft): 4,788' See Attached Schematic 4-1/2" Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: July 22, 2020 9,595'5,026' 4-1/2" 7,982' Perforate Repair Wepair Well Exploratory Stratigraphic Development Service BOP TestMechanical Integrity Test Location Clearance No No Wellbore schematic Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 9:12 am, Jul 16, 2020 320-300 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.07.15 15:00:53 -08'00' Taylor Wellman DSR-7/16/2020VTL 7/21/20 X 10-404 SFD 7/16/20CO 701C SFD 7/16/2020Comm. 7/22/2020 dts 7/21/2020 JLC 7/22/2020 RBDMS HEW 7/24/2020 Capillary String Well: Susan Dionne 05 Date: 7/8/2020 Well Name: Susan Dionne 05 API Number: 50-133-20562-00 Current Status: Online Gas Well Leg: N/A Estimated Start Date: 7/22/2020 Rig: NA Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 206-088 First Call Engineer: Michael Quick (907) 777-8442 (O) (907) 317-2969 (C) Second Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (M) AFE Number: Current Surface Pressure: 45 psi Maximum Expected BHP: 500 psi @ 3,600’ TVD Max. Potential Surface Pressure: 450 psi (Based on actual shut in WHP) Brief Well Summary SD-05 was drilled as a grassroots well to target gas sands in the Tyonek formations in 2006. The well was initially completed in the Tyonek. The patches across the Tyonek intervals (5,735’-5,735’ and 8,270’-8,276’ md) were set in 2006. A coil tubing cement plug was set from 9,325’ to 8,090’ md in 2007. In 2007 the Beluga 135 zone was perforated. In 2013 the Beluga 130 and 132 sands were perforated. In November of 2016, a 2-3/8” velocity string was installed in the well to a depth of 5,106’. The plunger lift system that was previously installed was removed in June 2020. The purpose of this work/sundry is to run a capillary line inside of the 2-3/8” tubing to inject soap to help lift the well. NOTE: A SSV on this well was recently installed in the vertical run of the tree. Running the cap string will require this SSV to be locked open, and the SSV that is in the horizontal run of the flowline will be used, as it was in the past when a cap string was installed in this well. Capstring Procedure: 1. MIRU Cap String Truck, PT lubricator to 2,500 psi Hi 250 Low. 2. Install wellhead packoff. 3. PU 3/8” capillary string. RIH and set @ 4,800’ to 5,150’ (+/-). 4. Set spool of remaining line near well. 5. Rig down Cap String Truck. 6. Turn well over to production. Attachments: 1. Actual Schematic 2. Proposed Schematic _____________________________________________________________________________________ Updated by DMA 07-07-20 SCHEMATIC Cook Inlet Basin, Alaska Middle Ground Shoal Last Completed: 02-28-1992 Oil Well ->Water injector -> Gas producer for Platform _____________ Ninilchik FieldCook Inlet BasCook Inlet Bas Well #: Susan Dionne 05 Middle Ground ShoalMiddle Ground Shoal Last Completed:Last Completed: Last Completed: Oil W ll >W t i j tt 8/7/200602-28-199202-28-1992 GdG PBTD = 7,532’ TD = 9,600’ MAX HOLE ANGLE = 61.5O55 @ 1,434’ 10 9 RKB: MSL = 156’ / 21’ AGL 7” TOC tagged @ 7,532’ MD on 8/30/2010 20” 9-5/8” 1 2 3 4-1/2”11 24 TOC tagged @ 9,341’ CTM on 5/31/2007 5&6 7 8 4 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm CMT Top 20"Conductor 133# / K-55 / PE 18.73”Surf 91' 9-5/8" Surface 40# / L-80 / BTC 8.835” Surf 1,630' 12ppg/ Surface 7"Intermediate 26# / L-80 / BTC 6.276”Surf 4,788'Surface 4-1/2"Liner 12.6# / L-80 / Hydril 563 3.958”4,569'9,595' TUBING DETAIL 4-1/2" Tubing 12.6#/L-80/Buttress Mod 3.958” Surf 4,569’ 2-3/8" Velocity String 4.7#/L-80/8Rnd EUE 1.995” Surf 5,106’ JEWELRY DETAIL No Depth Length ID OD Item 1 2,382 3.858”5.93”Baker Chemical Injection Nipple 2 4,569'9.55’ZXP Liner Packer w/ 15' Tieback Extension 3 4,609'7.97’Flex Lock Liner Hanger 4 5,040’ 3.72’ 1.875” 3.248”HAL XA Sliding Sleeve (X nipple profile at top of sleeve) 5 5,089’1.53’1.921”2.985”Ratch Latch w/ seal assembly 6 5,090’2.53’1.905”3.75”WL Set Perma-Series Pkr 7 5,098’1.28’1.875”2.72”2-3/8” X Nipple 8 5,106’0.45’1.995”3.52”WLEG 9 6,984'4’PAC Valve 10 9,467'Landing Collar 11 9,509'Float Collar 12 9,593'Float Shoe PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status BLG-130 5,163’ 5,173’ 3,567’ 3,576’10 2/21/13 Open BLG-130 5,251’5,253’3,650’3,652’10 2/20/13 Open BLG-132 5,247’ 5,257’ 3,647’ 3,656’10 2/21/13 Open BLG-135 5,317'5,343'3,714'3,739'26'6/7/07 Open Tyonek 5,735'5,737'4,123'4,125'2'10/26/06 Squeezed & Casing Patched T-65 8,270'8,276'6,657'6,663'6'10/24/06 Squeezed & Casing Patched T-83 8,508'8,524'6,895'6,911'16'5/31/08 Squeezed T-140 9,263'9,289'7,650'7,676'26'5/31/08 Squeezed OPEN HOLE / CEMENT DETAIL 9-5/8" 12-1/4" hole, Cmt w/ 404 sks (180 bbls) 12 ppg Type 1 cmt with 30 bbls, 12 ppg cmt to surface. (with partial lost returns) 7" 8-1/2" hole, Cmt w/ 254 sks (111.7 bbls) 12.5 ppg type G Lead, plus 197 sks (40.9 bbls) 15.8 ppg type G Tail. Bump plug, 15 bbls contaminated with 5 bbls cmt to surface, 100% returns, floats held. 4-1/2" 7" hole, Cmt w/ 20 bbl 10.5 ppg spacer followed by 330 sks (118.6 bbls) 13.0 ppg 8,045' KB cmt top from CBL run 8/7/2006. Lost circ w/83 bbls cmt displaced. PAC valve opened and immediately closed. Perfed 5,735' - 5,737' (Owen 3-3/8" 6 spf) to cmt above 120 sks (43 bbls) 13.0 ppg Lead followed by 50 sks (10 bbls) 15.8 ppg Tail 7.6 bbls cmt returns to surface. INCLINATION DETAIL KOP @ 200' MD/TVD Build 5.0 deg/100' from 200-1434' MD Hold 61.5 deg from 1434-2700' MD Drop 2 deg/100' to 5900' MD Hold 1.0 deg from 5900' to TD at 9,600' MD Azimuth: 220.7 deg. _____________________________________________________________________________________ Updated by DMA 09-18-18 PROPOSED SCHEMATIC Cook Inlet Basin, Alaska Middle Ground Shoal Last Completed: 02-28-1992 Oil Well ->Water injector -> Gas producer for Platform _____________ Ninilchik FieldCook Inlet BasCook Inlet Bas Well #: Susan Dionne 05 Middle Ground ShoalMiddle Ground Shoal Last Completed:Last Completed: Last Completed: Oil W ll >W t i j tt 8/7/200602-28-199202-28-1992 GdG PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status BLG-130 5,163’ 5,173’ 3,567’ 3,576’10 2/21/13 Open BLG-130 5,251’5,253’3,650’3,652’10 2/20/13 Open BLG-132 5,247’ 5,257’ 3,647’ 3,656’10 2/21/13 Open BLG-135 5,317'5,343'3,714'3,739'26'6/7/07 Open Tyonek 5,735'5,737'4,123'4,125'2'10/26/06 Squeezed & Casing Patched T-65 8,270'8,276'6,657'6,663'6'10/24/06 Squeezed & Casing Patched T-83 8,508'8,524'6,895'6,911'16'5/31/08 Squeezed T-140 9,263'9,289'7,650'7,676'26'5/31/08 Squeezed PBTD = 7,532’ TD = 9,600’ MAX HOLE ANGLE = 61.5O55 @ 1,434’ 10 9 RKB: MSL = 156’ / 21’ AGL 7” TOC tagged @ 7,532’ MD on 8/30/2010 20” 9-5/8” 1 2 3 4-1/2”11 12 TOC tagged @ 9,341’ CTM on 5/31/2007 5&6 7 8 4 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm CMT Top 20"Conductor 133# / K-55 / PE 18.73”Surf 91' 9-5/8" Surface 40# / L-80 / BTC 8.835” Surf 1,630' 12ppg/ Surface 7"Intermediate 26# / L-80 / BTC 6.276”Surf 4,788'Surface 4-1/2"Liner 12.6# / L-80 / Hydril 563 3.958”4,569'9,595' TUBING DETAIL 4-1/2" Tubing 12.6#/L-80/Buttress Mod 3.958” Surf 4,569’ 2-3/8" Velocity String 4.7#/L-80/8Rnd EUE 1.995” Surf 5,106’ JEWELRY DETAIL No Depth Length ID OD Item 1 2,382 3.858”5.93”Baker Chemical Injection Nipple 2 4,569'9.55’ZXP Liner Packer w/ 15' Tieback Extension 3 4,609'7.97’Flex Lock Liner Hanger 4 5,040’ 3.72’ 1.875” 3.248”HAL XD Sliding Sleeve (X nipple profile at top of sleeve) 5 5,089’1.53’1.921”2.985”Ratch Latch w/ seal assembly 6 5,090’2.53’1.905”3.75”WL Set Perma-Series Pkr 7 5,098’1.28’1.875”2.72”2-3/8” X Nipple 8 5,106’0.45’1.995”3.52”WLEG 9 6,984'4’PAC Valve 10 9,467'Landing Collar 11 9,509'Float Collar 12 9,593'Float Shoe OPEN HOLE / CEMENT DETAIL 9-5/8" 12-1/4" hole, Cmt w/ 404 sks (180 bbls) 12 ppg Type 1 cmt with 30 bbls, 12 ppg cmt to surface. (with partial lost returns) 7" 8-1/2" hole, Cmt w/ 254 sks (111.7 bbls) 12.5 ppg type G Lead, plus 197 sks (40.9 bbls) 15.8 ppg type G Tail. Bump plug, 15 bbls contaminated with 5 bbls cmt to surface, 100% returns, floats held. 4-1/2" 7" hole, Cmt w/ 20 bbl 10.5 ppg spacer followed by 330 sks (118.6 bbls) 13.0 ppg 8,045' KB cmt top from CBL run 8/7/2006. Lost circ w/83 bbls cmt displaced. PAC valve opened and immediately closed. Perfed 5,735' - 5,737' (Owen 3-3/8" 6 spf) to cmt above 120 sks (43 bbls) 13.0 ppg Lead followed by 50 sks (10 bbls) 15.8 ppg Tail 7.6 bbls cmt returns to surface. INCLINATION DETAIL KOP @ 200' MD/TVD Build 5.0 deg/100' from 200-1434' MD Hold 61.5 deg from 1434-2700' MD Drop 2 deg/100' to 5900' MD Hold 1.0 deg from 5900' to TD at 9,600' MD Azimuth: 220.7 deg. Capillary String Proposed to Install Top Bottom MD 0’±5,100’ TVD 0’±3,507’ From:Mike Quick To:Loepp, Victoria T (CED) Cc:Donna Ambruz Subject:RE: [EXTERNAL] Ninilchik Unit S Dionne 5(PTD 206-088, Sundry 320-300) Install Capillary String Date:Tuesday, July 21, 2020 12:22:32 PM Hello Victoria – Yes, the SSV in the horizontal run has had routine state testing. This field is on a 180 day test cycle, November and May testing months. This SSV in the horizontal run was locked open (not removed or modified) in May 2020 when the plunger lift assist system was installed per sundry 319-503, along with the vertical run SSV. This plunger lift system was removed on 6/18/2020 – the horizontal SSV was not in use for less than 2 months while we tried the plunger lift system. The SSV in the horizontal run has been tested on the 180 day cycle and has passed, last tested 4/24/2020. Our initial plan was to leave the SSV in the vertical run of the tree locked open, but have now decided to remove the valve from the vertical run of the tree prior to running the cap string in this sundry request, in order to use the valve on another well if needed. The cap string install requires the SSV to be out of the tree run. Please let me know if you would like anything further on this sundry. Thanks, Mike From: Loepp, Victoria T (CED) [mailto:victoria.loepp@alaska.gov] Sent: Tuesday, July 21, 2020 11:03 AM To: Mike Quick <mquick@hilcorp.com> Subject: [EXTERNAL] Ninilchik Unit S Dionne 5(PTD 206-088, Sundry 320-300) Install Capillary String Mike, Has the SSV in the horizontal run had routine State testing? What are the testing requirements and history? Thanx, Victoria Victoria Loepp Senior Petroleum Engineer State of Alaska Oil & Gas Conservation Commission 333 W. 7th Ave Anchorage, AK 99501 Work: (907)793-1247 Victoria.Loepp@alaska.gov CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Victoria Loepp at (907)793-1247 or Victoria.Loepp@alaska.gov The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: Install Plunger Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 9,600 feet 7,532 feet true vertical 7,987 feet N/A feet Effective Depth measured 7,532 feet 4,569; 5,090 feet true vertical 5,920 feet 3,028; 3,498 feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic 4-1/2" 12.6# / L-80 4,569' MD 4,569' TVD Tubing (size, grade, measured and true vertical depth)2-3/8" 4.7# / L-80 5,106' MD 3,513' TVD ZXP Liner Pkr; 4,569' MD 3,028' TVD Packers and SSSV (type, measured and true vertical depth)WL Pkr; N/A 5,090' MD 3,498' TVD N/A; N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Taylor Wellman 777-8449 Contact Name:Ted Kramer Authorized Title:Operations Manager Contact Email: Contact Phone:777-8420 tkramer@hilcorp.com Senior Engineer:Senior Res. Engineer: 8,930psi Burst 3,060psi91' 1,298' 7,240psi 5,750psi Collapse 1,500psi 3,090psi 5,410psi 7,500psi Casing Structural 20" 9-5/8" 7" Length 91' 1,630' 4,788' Conductor Surface Intermediate Production Authorized Signature with date: Authorized Name: 3 Casing Pressure Liner 5,026' 359 7,982' 0 Representative Daily Average Production or Injection Data 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 319-503 40 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 5 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 206-088 50-133-20562-00-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 2. Operator Name:Hilcorp Alaska, LLC 41117 Ninilchik Unit S Dionne 5 N/A FEE-CIRI; C-061505 4,788' Plugs Junk measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Ninilchik Field / Beluga-Tyonek GasN/A measured TVD Tubing PressureOil-Bbl measured true vertical Packer 4-1/2" 3,219' WINJ WAG 576 Water-Bbl MD 91' 1,630' 9,595' 83 t Fra O 6. A G L PG , R Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 2:53 pm, Jun 24, 2020 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.06.24 14:08:30 -08'00' Taylor Wellman RBDMS HEW 6/24/2020 DSR-6/24/2020 lift system gls 6/2/520 Rig Start Date End Date 5/10/20 5/31/20 05/31/2020 - Sunday Drop plunger back into well. Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name SD-05 50-133-20562-00-00 206-088 05/27/2020 - Wednesday On location, TGSM, JSA, PERMIT. Rig up W/L, PT lubricator. RIH w/ 1.74" LIB to 1,375' KB, slow down, continue in hole to 5,026' KB WT, POOH. Fluid appears to be at 3,500' KB (plunger was lodged at 1,375'). OOH w/ imprint of plunger. RIH w/ 1.5" GS to 5,026' KB WT, POOH. OOH w/ plunger w/ soap stick inside. RIH w/ 1.74" LIB to 5,027' KB WT, POOH. OOH w/ no impression (possibly sand). RIH w/ 1.75" x 6' pump bailer to 5,027' KB WT, POOH. OOH w/ empty bailer, bottom shows fishing neck of bump stop. Rig down W/L, depart site. 05/10/2020 - Sunday Rig up on well. RIH w/ 1.85" GR to 5,322' KB, tag bottom, POOH. RIH w/ 2-3/8" BO 142 Shifting Tool to 5,050' KB, set tool, POOH. RIH w/ 2" SB w/ bumper tool to 5,050' KB, set tool, POOH. Assist with changing out tree. Depart site. Daily Operations: 05/26/2020 -Tuesday Discussed dropping rate since bumper spring/plunger installed. Decision made to retrieve plunger. _____________________________________________________________________________________ Updated by DMA 06-17-20 SCHEMATIC Cook Inlet Basin, Alaska Middle Ground Shoal Last Completed: 02-28-1992 Oil Well ->Water injector -> Gas producer for Platform Ninilchik Field Well #: Susan Dionne 05 Last Completed: 8/7/2006 CASING DETAIL Size Type Wt/ Grade/ Conn ID Top Btm CMT Top 20" Conductor 133# / K-55 / PE 18.73” Surf 91' 9-5/8" Surface 40# / L-80 / BTC 8.835” Surf 1,630' 12ppg/ Surface 7" Intermediate 26# / L-80 / BTC 6.276” Surf 4,788' Surface 4-1/2" Liner 12.6# / L-80 / Hydril 563 3.958” 4,569' 9,595' TUBING DETAIL 4-1/2" Tubing 12.6#/L-80/Buttress Mod 3.958” Surf 4,569’ 2-3/8" Velocity String 4.7#/L-80/8Rnd EUE 1.995” Surf 5,106’ JEWELRY DETAIL No Depth Length ID OD Item 1 2,382 3.858” 5.93” Baker Chemical Injection Nipple 2 4,569' 9.55’ ZXP Liner Packer w/ 15' Tieback Extension 3 4,609' 7.97’ Flex Lock Liner Hanger 4 VARIES Bypass Plunger (Ball & Sleeve) 5 5,050’ Bumper Spring 5/10/20 6 5,040’ 3.72’ 1.875” 3.248” HAL XD Sliding Sleeve (X nipple profile at top of sleeve) 7 5,089’ 1.53’ 1.921” 2.985” Ratch Latch w/ seal assembly 8 5,090’ 2.53’ 1.905” 3.75” WL Set Perma-Series Pkr 9 5,098’ 1.28’ 1.875” 2.72” 2-3/8” X Nipple 10 5,106’ 0.45’ 1.995” 3.52” WLEG 11 6,984' 4’ PAC Valve 12 9,467' Landing Collar 13 9,509' Float Collar 14 9,593' Float Shoe PERFORATION DETAIL Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status BLG-130 5,163’ 5,173’ 3,567’ 3,576’ 10 2/21/13 Open BLG-130 5,251’ 5,253’ 3,650’ 3,652’ 10 2/20/13 Open BLG-132 5,247’ 5,257’ 3,647’ 3,656’ 10 2/21/13 Open BLG-135 5,317' 5,343' 3,714' 3,739' 26' 6/7/07 Open Tyonek 5,735' 5,737' 4,123' 4,125' 2' 10/26/06 Squeezed & Casing Patched T-65 8,270' 8,276' 6,657' 6,663' 6' 10/24/06 Squeezed & Casing Patched T-83 8,508' 8,524' 6,895' 6,911' 16' 5/31/08 Squeezed T-140 9,263' 9,289' 7,650' 7,676' 26' 5/31/08 Squeezed OPEN HOLE / CEMENT DETAIL 9-5/8" 12-1/4" hole, Cmt w/ 404 sks (180 bbls) 12 ppg Type 1 cmt with 30 bbls, 12 ppg cmt to surface. (with partial lost returns) 7" 8-1/2" hole, Cmt w/ 254 sks (111.7 bbls) 12.5 ppg type G Lead, plus 197 sks (40.9 bbls) 15.8 ppg type G Tail. Bump plug, 15 bbls contaminated with 5 bbls cmt to surface, 100% returns, floats held. 4-1/2" 7" hole, Cmt w/ 20 bbl 10.5 ppg spacer followed by 330 sks (118.6 bbls) 13.0 ppg 8,045' KB cmt top from CBL run 8/7/2006. Lost circ w/83 bbls cmt displaced. PAC valve opened and immediately closed. Perfed 5,735' - 5,737' (Owen 3-3/8" 6 spf) to cmt above 120 sks (43 bbls) 13.0 ppg Lead followed by 50 sks (10 bbls) 15.8 ppg Tail 7.6 bbls cmt returns to surface. INCLINATION DETAIL KOP @ 200' MD/TVD Build 5.0 deg/100' from 200-1434' MD Hold 61.5 deg from 1434-2700' MD Drop 2 deg/100' to 5900' MD Hold 1.0 deg from 5900' to TD at 9,600' MD Azimuth: 220.7 deg. plunger lift equipment 4 VARIES Bypass Plunger (Ball & Sleeve) 5 5,050’ Bumper Spring 5/10/20 THE STATE 01ALASKA GOVERNOR MIKE DUNLEAVY Bo York Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Ninilchik Field, Beluga-Tyonek Gas Pool, NU S Dionne 5 Permit to Drill Number: 206-088 Sundry Number: 319-503 Dear Mr. York: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.alaska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, ssie L. Chmielowski 1i Commissioner DATED this 20 day of December, 2019. RBDMS LCvJJAN 0 2 2020 SCANNED )Ari 0 2 2020 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 RECEIVE® NOV 0 6 2019 X2.12-01 It A®GCC 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Install Plunger ❑� 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development Q Stratigraphic ❑ Service ❑ 206-088 r 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-133-20562-00-00 r 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 701A r Will planned perforations require a spacing exception? Yes ❑ No Ninilchik Unit S Dionne 5 r 9. Property Designation (Lease Number): 10. Field/Pool(s): FEE-CIRI, C-061505 I Ninilchik Field / Beluga-Tyonek Gas r 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 9,600' 7,987' 7,532' 5,920' -636 psi 7,532' NIA Casing Length Size MD TVD Burst Collapse Structural Conductor 91' 20" 91' 91' - 1,500 psi Surface 1,630' 9-5/8" 1,630' 1,298' 5,750 psi 3,090 psi Intermediate 4,788' 7" 4,788' 3,219' 7,240 psi 5,410 psi Production Liner 5,026 41/2" 1 9,595' 7,982' 1 8,930 psi 7,500 psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: 2-318" Tubing Grade: 4.7# / L-80 Tubing MD (ft): 5,106' See Attached Schematic See Attached Schematic 4-1/2" 12.6# / L-80 4,569' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): ZXP Liner Packer; WL Pkr / SSSV - N/A Packer 4,569' (MD) 3,028' (TVD); 5,090' MD / 3,498' TVD / SSSV - N/A 12. Attachments: Proposal Summary ID Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development I] Service ❑ 14. Estimated Date for 15. Well Status after proposed work: November 20, 2019 Commencing Operations: OIL E]WINJ E]WDSPL ❑ Suspended E] GAS E r WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Bo York 8448345 Contact Name: Christina Twogood Authorized Title: Operations Manager Contact Email: CtwO Dod NICor .Cont Contact Phone: 777-8443 `t Authorized Signature.` - ( Date: I COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: <J Pk,. ,, l.wr4 w - Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ,� /Location Clearance / n Other: :5,15V /,1,.., — 1., ih tkr Fi � �k r,,, i% -Free. n � o L_ l� rlrc ^ Sx4 f ipi�.y Orle5s�tn� t 1 !moi 2oOZ� /�/f Post Initial Injection MIT Req'd? Yes ❑ No Q d �� Spacing Exception Required? Yes No Subsequent Form Required: ❑ ' y a� 3BDMS 1�6/ JAN 0 2 1020 APPROVED BY Approved by: i iL_.. COMMISSIONER THE COMMISSION Date: 12d? -O Form 10-403 Revised 4/? / A oved lication Is % , I r�p tis"rgr�Lh! data of a + ' A Submit Form and pp pp approval. Aaachmen s in Duplicate � I ��%19 ,n Hil." Alaska, M Plunger Lift Well: SD -05 Date: 11/6/2019 Well Name: SD -05 API Number: 50-133-20588-00-00 Current Status: Producing Gas Well Leg: N/A Estimated Start Date: 11/20/2019 Rig: Reg. Approval Req'd? 10-403 Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 209-168 First Call Engineer: Christina Twogood (907) 777-8443 (0) (907) 378-7323 (M) Second Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (M) AFE Number: Current Surface Pressure: 339 psi (Based on 7/12/18 Shut-in pressure) Max. Expected BHP: 1009 psi (@ 3,739' TVD (Based on 6/23/17 Be1120 RFT data) Max. Potential Surface Pressure: 636 psi (@ 3,739' TVD) (Based on expected BHP and gas gradient to surface (0.1 psi/ft)) Brief Well Summary SD -05 is a gas production well completed in the Beluga and Tyonek sands. In November 2016 the well was worked over for a velocity string installation. The purpose of this sundry/work is to install a plunger lift system to keep the well from loading up and killing production due to increased line pressure. Slickline Procedure (Prepare Tubing): -7 1. MIRU Slickline Unit. Pressure test to 250 psi Low /si High. 2. MU BHA, drift tubing and tag for fill. 3. If necessary, perform cleanout run. All debris/tight spots must be removed prior to running the bumper spring and plunger. 4. RD Slickline unit. E -Line Procedure (Bumper Spring Installation): 76" 1. MIRU E -Line and pressure control equipment. PT lubricator to 250 psi Low / 1 psi High. 2. RIH with GPT tool and find fluid level. 3. MU Bumper Spring Assembly. 4. RIH and set in X Profile located just above the Sliding Sleeve at ±5,040'. 5. POOH and RD E -Line Lubricator. Plunger Installation Procedure: 1. MU plunger lubricator to wellhead. PT to 250 psi Low/ 1i High. 2. Prepare to drop the plunger by placing on the catcherevef I in the bottom half of the plunger lubricator. 3. Reinstall the top of the plunger lubricator. Slowly open the master valve to pressurize the lubricator and test for leaks. If a leak is found, close the master valve and depressurize the lubricator to repair the leaks. 4. If no leaks are found, release the plunger from the catcher to allow it to fall. 5. Shut the well in, depressurize the plunger lubricator and remove the upper section to RU the E -Line lubricator. K llilcory Alneka, LL E -Line Procedure (Plunger Installation): 1. RU the E -Line lubricator. PT to 250 psi Low / 1,000 psi High. 2. MU Blind Box BHA and "chase" the plunger to the bumper spring. 3. Once the plunger is on the bumper spring, shut the well in. 4. POOH and RD E -Line unit. 5. Turn well over to production. Plunger Lift Well: SD -05 Date: 11/6/2019 / ( N� Co �vt51 t C f Sc t-� 1 �t^ fes"" I. Attachments 1. Current Well Schematic 2. Proposed Well Schematic 3. Downhole Operations Flow Chart 4. Surface Flow Diagram 0 Hilmm Alaskn, LLC PIQR MSL=156' 121' PGL PBTD=7,537 TD=9,600' MAX HOLE ANGLE = 61.50 (W.1,434' SCHEMATIC CASING DETAIL Ninilchik Field Well #: Susan Dionne 05 Last Completed: 8/7/2006 Size Type Wt/Grade/Conn ID Top Btm CMTTop 20" Conductor 133#/K-55/PE 18.73" Surf 91' 4,569' 9-5/8" Surface 40#/L-80/BTC 8.835" Surf 1,630' Surface 7" Intermediate 26#/L-80/BTC 6.276" Surf 4,788' Surface 4-1/2" Liner 12.6#/L-80/Hydril 563 3.958" 4,569' 9,595' 2.985" TUBING DETAIL 4-1/2" Tubing 12.6#11.-80/Buttress Mod 3.958" Surf 4,569' OD 2-3/8" Velocity String 4.7#/L-80/8Rnd EU, 1.995" Surf 5,106' 3.858" JEWELRY DETAIL No Depth Length ID OD Item 1 2,382 130 3.858" 5.93" Baker Chemical Injection Nipple 2 4,569' 9.55' Open 130 ZXP Liner Packer w/ 15' Tieback Extension 3 4,609' 7.97' 10 2/20/13 Flex Lock Liner Hanger 4 5,040' 3.72' 1.875" 3.248" HAL XD Sliding Sleeve (X nipple profile at top of sleeve) 5 5,089' 1.53' 1.921" 2.985" Ratch Latch w/ seal assembly 6 51090' 2.53' 1.905" 3.75" WL Set Perma-Series Pkr 7 5,098' 1.28' 1.875" 2.72" 2-3/8" X Nipple 8 5,106' 0.45' 1.995" 3.52" WLEG 9 6,984' 4' 8,508' 8,524' PAC Valve 30 9,467' 5/31/08 Squeezed W Landing Collar 31 9,509' 7,676' 26' 5/31/08 Float Collar 12 9,593' Float Shoe PERFORATION DETAIL Ie (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status 130 5,163' 5,173' 3,567' 3,576' 10 2/21/13 Open 130 5,251' 5,253' 3,650' 3,652' 10 2/20/13 Open 132 5,247' 5,251 3,647' 3,656' 10 2/21/13 Open 135 5,317' 5,343' 3,714' 3,739' 26' 6/7/07 Open ek 5,735' 5,737' 4,123' 4,125' 2' 10/26/06 Squeezed & Casing Patched i5 8,270' 8,276' 6,657' 6,663' 6' 10/24/06 Squeezed & Casing Patched 13 8,508' 8,524' 6,895' 6,911' 16' 5/31/08 Squeezed W 9,263' 9,289' 7,650' 7,676' 26' 5/31/08 5 ueezed OPEN HOLE/ CEMENT DETAIL 9-5/81, 12-1/4" hole, Cmt w/ 404 sks (180 bbis) 12 ppg Type 1 cmt with 30 bbis, 12 ppg cmt to surface. (with partial lost returns) 8-1/2" hole, Cmt w/ 254 sks (111.7 bbls)12.5 ppg type G Lead, plus 197 sks (40.9 bbis)15.8 7" ppg type G Tail. Bump plug, 15 bbis contaminated with 5 bbis cmt to surface, 100% returns, floats held. 7" hole, Cmt w/ 20 bbl 10.5 ppg spacer followed by 330 sks (118.6 bbls)13.0 ppg 8,045' KB cmt 4-1/2" top from CBL run 8/7/2006. Lost circ w/83 bbis cmt displaced. PAC valve opened and immediately closed. Perfed 5,735'- 5,737' (Owen 3-3/8" 6 spf) to cmt above 120 sks 143 bbls) 13.0 ppg Lead followed by 50 sks (10 bbis) 15.8 ppg Tail 7.6 bbis cmt returns to surface. INCLINATION DETAIL KOP @ 200' MD/- VD Build 5.0 deg/100' from 200-1434' MD Hold 61.5 deg from 1434-2700' MD Drop 2 deg/100' to 5900' MD Hold 1.0 deg from 5900' to TO at 9,600' MD Azimuth: 220.7 deg. Updated by DMA 09-18-18 PROPOSED SCHEMATIC Hilcorp Alaska, LLC Ni Wt.= t5a' 121' AM PBTD=7,532' TD=9,600' MAX HOLE ANGLE = 61.50 @ 1,434' Ninilchik Field Well #: Susan Dionne 05 Last Completed: 8/7/2006 CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm CMT Top 20" Conductor 133#/K-55/PE 18.73" Surf 91' 4,569' 9-5/8" Surface 40#/L-80/BTC 8.835" Surf 1,630' Surface Surface 7" Intermediate 26#/L-80/BTC 6.276" Surf 4,788' Surface 4-1/2" Liner 12.6# / L-80 / Hydril 563 3.958" 4,569' 9,595' 5,343' TUBING DETAIL 4-1/2" Tubing 12.6#/L-80/Buttress Mod 3.958" Surf 4,569' Item 2-3/8" Velocity String 4.7#/L-80/8Rnd EUE 1.995" Surf 5,106' Baker Chemical Injection Nipple JEWELRY DETAIL No Depth Length ID OD Item 1 2,382 L30 3.858" 5.93" Baker Chemical Injection Nipple 2 4,569' 9.55' Open L30 ZXP Liner Packer w/ 15' Tieback Extension 3 4,609' 7.97' 30 2/20/13 Flex Lock Liner Hanger 4 varies 5,257' 3,647' 3,656' Bypass Plunger (Ball &Sleeve) 5 "5,020' L35 5,317' 5,343' Bumper Spring 6 5,044 3.72' 1.875" 3.248" HAL XD Sliding Sleeve (X nipple profile at top of sleeve) 7 5,089' 1.53' 1.921" 2.985" Ratch Latch w/ seal assembly 8 5,090' 2.53' 1.905" 3.75" WL Set Perma-Series Pkr 9 5,098' 1.28' 1.875" 2.72" 2-3/8" X Nipple 10 5,106' 0.45' 1.995" 3.52" WLEG 11 1 4' 26' 5/31/08 PAC Valve 12 9,467' Landing Collar 13 9,509' Float Collar 14 9,593' Float Shoe PERFORATION DETAIL ie (Mo) Btm (MD) Top (TVD) Btm (ND) FT Date Status L30 5,163' 5,173' 3,567' 3,576' 10 2/21/13 Open L30 5,251' 5,253' 3,650' 3,652' 30 2/20/13 Open L32 5,247' 5,257' 3,647' 3,656' 10 2/21/13 Open L35 5,317' 5,343' 3,714' 3,739' 26' 6/7/07 Oen ek 5,735' 5,737' 4,123' 4,125' 2' 10/26/06 Squeezed & Casing Patched 15 8,270' 8,276' 6,657' 6,663' 6' 10/24/06 Squeezed & Casing Patched '3 8,508' 8,524' 6,895' 6,911' 16' 5/31/08 Squeezed 70 9,263' 9,289' 7,650' 7,676' 26' 5/31/08 Squeezed OPEN HOLE / CEMENT DETAIL 9_5/8, 12-1/4" hole, Cmt w/ 404 sks (180 bbis) 12 ppg Type 1 cmt with 30 bbls, 12 ppg cmt to surface. (with partial lost returns) 8-1/2" hole, Cmt w/ 254 sks 1111.7 bbls)12.5 ppg type G Lead, plus 197 sks (40.9 bbls)15.8 7" ppg type G Tail. Bump plug, 15 bbls contaminated with 5 bbls cmt to surface, 100% returns, floats held. 7" hole, Cmt w/ 20 bbl 10.5 ppg spacer followed by 330 sks (118.6 bbls) 13.0 ppg 8,045' KB cmt 4-1/2' top from CBL run 8/7/2006. Lost circ w/83 bbls cmt displaced. PAC valve opened and immediately closed. Perfed 5,735'- 5,737' (Owen 3-3/8" 6 spf) to cmt above 120 sks (43 bbls) 13.0 ppg Lead followed by 50 sks (10 bbls)15.8 ppg Tail 7.6 bbls cmt returns to surface. INCLINATION DETAIL KOP La1200' MD/IVD Build 5.0 deg/100' from 200-1434' MD Hold 61.5 deg from 1434-2700' MD Drop 2 deg/100' to 5900' MD Hold 1.0 deg from 5900' to TD at 9,600' MD Azimuth: 220.7 deg. Updated by CMT 11-6-2019 SD -05 Plunger Lift ON W\ n s O m W (D m Q G m (D 1 0 0 n MR K O O T O m m Z 00 0 M m0 p 00 0 0 3 0 0 m 0 Z • • t D W W D w Cl D m T D�mm3 Z Wm A Z T ~G1�O D v r r z C) T r r M \ m m m f Z A = O m m O D MOO O O Q O m - W O 09 D T A m r T 0 r m T D O r r_ Z 0 LD100 Dr= D A A rp A D m m 3 T = O m O in 3 -M m m 0'oz A 09 V; W m D Ro r m m m m Schwartz, Guy L (CED) From: Christina Twogood - (C) <ctwogood@hilcorp.com> Sent: Thursday, December 19, 2019 4:05 PM To: Schwartz, Guy L (CED); Regg, James B (CED) Cc: Ted Kramer; Donna Ambruz Subject: RE: [EXTERNAL] RE: SD -05 Plunger Lift (PTD 206-088) Attachments: SD -05 Surface Bypass Plunger Layout 12-19-2019 vl.pdf Follow Up Flag: Follow up Flag Status: Flagged G uy, On the first installation, Hilcorp is in agreement with the proposed placement of the SSV in the vertical section of the wellhead. Regarding the pressure test procedure for installation of the plunger system, the pressure tests relevant to the downhole operations have been described in the submitted procedure as outlined below: 1. Slickline PT (for drift/tag run) 2. E -Line PT (for bumper spring installation in wellbore) 3. Plunger Lubricator PT (for plunger lubricator/catcher installation at wellhead) 4. E -Line PT (for plunger installation in wellbore) After these operations and the installation of the additional surface equipment (piping, valves, lubricator), the equipment will be pressure tested in excess of the MPSP prior to live pressure from the well being placed on the system as follows: 1. Close the lower master valve and flowline block valve. 2. PT to 250 psi Low / 1,000 psi High. 3. After successful test, open lower master valve and flowline block valve. 4. Perform both a performance and a function test of the SSV (as per guidelines in 20 AC 25.265.h) prior to coming online. The vendor will be on site for the initial installation. Christina Twogood Operations Engineer Kenai Asset Team, Hilcorp Alaska 3800 Centerpoint Dr., Anchorage, AK 99503 (w) 907-777-8443 (c) 907-378-7323 From: Schwartz, Guy L (CED) [mailto:guy.schwartz@alaska.gov] Sent: Wednesday, December 11, 2019 2:17 PM To: Christina Twogood - (C) <ctwogood@hilcorp.com>; Regg, James B (CED) <jim.regg@alaska.gov> Cc: Ted Kramer <tkramer@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com> Subject: RE: [EXTERNAL] RE: SD -05 Plunger Lift (PTD 206-088) Christina, Thanks for the email below. As we discussed on the phone the AOGCC is in agreement with your proposals/comments listed below with the exception of SSV placement. AOGCC's position is that the risk is minimal with SSV at wellhead in vertical run... even if the plunger did lodge across the SSV and lower master valve in the event of a unplanned SSV closure. In this case the swab valve is still available as a backup to shut-in the well (functions as a MV when using plunger lift). We see greater risk with having the SSV further from the wellhead with the extra threaded pipe and associated plunger hardware between it and the wellhead. Hilcorp can certainly provide additional documentation to the AOGCC that may impact our decision on SSV placement. The Plunger vendor may have more insight also ... but I do recall him saying it would not be a problem having the MV and SSV in the vertical run at our last meeting. The AOGCC will also need a written pressure test procedure for installation of the plunger system. I didn't see that in the sundry application . Is vendor going to be on site for the initial installation? Regards, Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AC)GCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending if to you, contact Guy Schwartz at (907-793-1226) or (Guv.schwartz@alaska.gov). From: Christina Twogood - (C) <ctwogood@hilcorp.com> Sent: Wednesday, December 4, 2019 3:13 PM To: Schwartz, Guy L (CED) <guy.schwa rtz@alaska.gov>; Regg, James B (CED) <iim.regg@alaska.gov> Cc: Ted Kramer <tkramer@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com> Subject: RE: [EXTERNAL] RE: SD -05 Plunger Lift (PTD 206-088) Guy and Jim, Thank you for meeting with Ted and I to discuss the Plunger Lift System planned for Susan Dionne #05. 1 have summarized key details from our discussion below. Pressure Testing of the Surface Equipment After installation of the additional surface equipment (piping, valves, lubricator) the equipment will be pressure tested in excess of the MPSP prior to live pressure from the well being placed on the system. How does the Controller communicate with the Choke? The current controller is wired to the choke and operates via manual commands set in the interface. The plunger lift system will function in the same way, with the new controller, for this operation. Will the plunger lift operation affect the SSV Pilot? The current SSV pilot is functioned based on the pressure switch on the flowline. The way the SSV pilot functions will not change with the installation of the Plunger Lift System. Is there wireline access through the plunger lubricator/plunger catcher? Yes, the plunger lubricator cap is removed to allow for wireline access to the wellbore, when required. Should the swab valve be removed? With the swab valve in place, it will be possible to keep the well on production in the event the Plunger Lift System is to be bypassed with the plunger removed. As such, Hilcorp plans to leave the swab valve as configured. Variance requested for threaded connections at surface - The Plunger Lubricator is designed such that the surface equipment installation is with threaded connections. - The Plunger Surface Equipment (excluding the Plunger Lubricator) can be installed using threaded or flanged connections. It is common practice for Hilcorp to install threaded Plunger Surface Equipment as the relevant wells, SD -05 included, are in the late stage of life and thereby at a very low pressure, making threaded connections an appropriate selection for this condition. - As such, Hilcorp requests a variance to allow for these threaded connections. Should the SSV be moved to the vertical portion of the wellhead? - The SSV is currently located in the horizontal section of the flow line, made up just after the wing valve coming off the flow cross from the wellhead. The additional footage added to the system is expected to be minimal (less than 10 ft total flow path), with the SSV still made up only a few feet from its current location. While the additional flow lines/connections increase the length of the surface flow path, thereby increasing the opportunity for a leak in the system upstream of the SSV, the flow characteristics are not expected to increase the likelihood over that which already exists in this system of a leak developing. However, Hilcorp believes that placing the SSV in the vertical portion of the wellhead introduces a greater risk based on the following: c In the event the SSV is closed with the plunger below it, the plunger may continue traveling to the surface (due to (1) rate of travel of the plunger, (2) time for SSV to fully close (up to 2 minutes) and (3) compressibility of gas within the fluid column) and collide with the partially or fully closed SSV, causing damage such that the SSV may fail. In the event the SSV is closed with the plunger across it, the plunger may prevent the SSV from fully closing, thereby preventing effective well control and causing an obstruction and/or damage such that the SSV may fail. In the event the SSV is closed with the plunger across it, the plunger may obstruct the master valve preventing its ability to close, thereby preventing effective well control. The current SSV variance is still applicable to well operations requiring the SSV to remain in the produced fluid stream while providing concurrent wellbore access. Based on the above considerations, Hilcorp requests that the SSV be allowed to remain in the horizontal section of the system. Please let us know if this is acceptable. Thank you, Christina Twogood Operations Engineer Kenai Asset Team, Hilcorp Alaska 3800 Centerpoint Dr., Anchorage, AK 95--3 (w)907-777-8443 (c) 907-378-7323 From: Schwartz, Guy L (CED) [mailto:guy.schwartz@alaska.gov] Sent: Wednesday, November 13, 2019 8:28 AM To: Christina Twogood - (C) <ctwogood@hilcorp.com> Cc: Ted Kramer <tkramer@hilcorp.com> Subject: [EXTERNAL] RE: SD -05 Plunger Lift (PTI) 206-088) Christina/Ted, We have some additional questions... is the vendor available to be part of the conversation also? Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226 1 or (Guv.schwartz@olaska.aoy). From: Christina Twogood - (C) <ctwogood@hilcorp.com> Sent: Wednesday, November 6, 2019 3:39 PM To: Schwartz, Guy L (CED) <guy.schwartz@alaska.gov> Cc: Ted Kramer <tkramer@hilcorp.com> Subject: SD -05 Plunger Lift (PTD 206-088) Guy, The sundry for SD -05 plunger lift system has been completed and should be arriving within the next day. I have included downhole and surface diagrams to describe the operations sequence and flow paths. If you would like for me or Ted to come by to go over these or you have additional questions on this operation we would be happy to come by to discuss. Thank you, Christina Twogood Operations Engineer Kenai Asset Team, Hilcorp Alaska 3800 Centerpoint Dr., Anchorage, AK 99503 (w) 907-777-8443 (c) 907-378-7323 The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Schwartz, Guy L (CED) From: Christina Twogood - (C) <ctwogood@hilcorp.com> Sent: Wednesday, December 4, 2019 3:13 PM To: Schwartz, Guy L (CED); Regg, James B (CED) Cc: Ted Kramer; Donna Ambruz Subject: RE: [EXTERNAL] RE: SD -OS Plunger Lift (PTD 206-088) Follow Up Flag: Follow up Flag Status: Flagged Guy and Jim, Thank you for meeting with Ted and I to discuss the Plunger Lift System planned for Susan Dionne #05. 1 have summarized key details from our discussion below. Pressure Testing of the Surface Equipment After installation of the additional surface equipment (piping, valves, lubricator) the equipment will be pressure tested in excess of the to live pressure from the well being placed on the system. How does the Controller communicate with the Choke? The current controller is wired to the choke and operates via manual commands set in the interface. The plunger lift system will function in the same way, with the new controller, for this operation. Will the plunger lift operation affect the SSV Pilot? The current SSV pilot is functioned based on the pressure switch on the flowline. The way the SSV pilot functions will not change with the installation of the Plunger Lift System. Is there wireline access through the plunger lubricator/plunger catcher? Yes, the plunger lubricator cap is removed to allow for wireline access to the wellbore, when required. Should the swab valve be removed? With the swab valve in place, it will be possible to keep the well on production in the event the Plunger Lift System is to be bypassed with the plunger removed. As such, Hilcorp plans to leave the swab valve as configured. 0 Variance requested for threaded connections at surface - The Plunger Lubricator is designed such that the surface equipment installation is with threaded connections. - The Plunger Surface Equipment (excluding the Plunger Lubricator) can be installed using threaded or flanged connections. It is common practice for Hilcorp to install threaded Plunger Surface Equipment as the relevant wells, SD -05 included, are in the late stage of life and thereby at a very low pressure, making threaded connections an appropriate selection for this condition. - As such, Hilcorp requests a variance to allow for these threaded connections. Should the SSV be moved to the vertical portion of the wellhead? - The SSV is currently located in the horizontal section of the flow line, made up just after the wing valve coming off the flow cross from the wellhead. The additional footage added to the system is expected to be minimal (less than 10 ft total flow path), with the SSV still made up only a few feet from its current location. While the additional flow lines/connections increase the length of the surface flow path, thereby increasing the opportunity for a leak in the system upstream of the SSV, the flow characteristics are not expected to increase the likelihood over that which SCANNED JAN 0 2 2020 already exists in this system of a le.,. developing. However, Hilcorp believes that placing the SSV in the vertical portion of the wellhead introduces a greater risk based on the following: o In the event the SSV is closed with the plunger below it, the plunger may continue traveling to the surface (due to (1) rate of travel of the plunger, (2) time for SSV to fully close (up to 2 minutes) and (3) compressibility of gas within the fluid column) and collide with the partially or fully closed SSV, causing damage such that the SSV may fail. o In the event the SSV is closed with the plunger across it, the plunger may prevent the SSV from fully closing, thereby preventing effective well control and causing an obstruction and/or damage such that the SSV may fail. o In the event the SSV is closed with the plunger across it, the plunger may obstruct the master valve preventing its ability to close, thereby preventing effective well control. The current SSV variance is still applicable to well operations requiring the SSV to remain in the produced fluid stream while providing concurrent wellbore access. Based on the above considerations, Hilcorp requests that the SSV be allowed to remain in the horizontal section of the system. Please let us know if this is acceptable. Thank you, Christina Twogood Operations Engineer Kenai Asset Team, Hilcorp Alaska 3800 Centerpoint Dr., Anchorage, AK 99503 (w)907-777-8443 (c) 907-378-7323 From: Schwartz, Guy L (CED) [mailto:guy.schwartz@alaska.gov] Sent: Wednesday, November 13, 2019 8:28 AM To: Christina Twogood - (C) <ctwogood@hilcorp.com> Cc: Ted Kramer <tkramer@hilcorp.com> Subject: [EXTERNAL] RE: SD -05 Plunger Lift (PTD 206-088) Christina/Ted, We have some additional questions... is the vendor available to be part of the conversation also? Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONF/DENTIAUTY NOTICE., This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, with, rirst saving or forwarding it, and, so that the AOGk�C is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793-1226) or (Guv Schwartz@alaska.aov). From: Christina Twogood - (C) <ctwoaood@hilcorp.com> Sent: Wednesday, November 6, 2019 3:39 PM To: Schwartz, Guy L (CED) <guy.schwartz@alaska.gov> Cc: Ted Kramer <tkramer@hilcorp.com> Subject: SD -05 Plunger Lift (PTD 206-088) Guy, The sundry for SD -05 plunger lift system has been completed and should be arriving within the next day. I have included downhole and surface diagrams to describe the operations sequence and flow paths. If you would like for me or Ted to come by to go over these or you have additional questions on this operation we would be happy to come by to discuss. Thank you, Christina Twogood Operations Engineer Kenai Asset Team, Hilcorp Alaska 3800 Centerpoint Dr., Anchorage, AK 99503 (w) 907-777-8443 (c) 907-378-7323 The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. If the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. THE STATE 01ALASKA GOVERNOR BILL WALKER Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission Re: Ninilchik Field, Beluga-Tyonek Gas Pool, Ninilchik Unit S Dionne 5 Permit to Drill Number: 206-088 Sundry Number: 318-413 Dear Mr. Helgeson: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.cogcc.alaska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, SW6�c Cathy P. Foerster Commissioner DATED this 3rday of October, 2018. RBDMd3(—OCT 0 3 2018 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.290 SEP 15 2010 AnC-CCC 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Install Capstring ❑� 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development D Stratigraphic ❑ Service ❑ 206-088 3. Address: 3800 Centerpoint Dr, Suite 1400 6. API Number: Anchorage Alaska 99503 50-133-20562-00-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 701A Will planned perforations require a spacing exception? Yes ❑ No ❑� Ninilchik Unit S Dionne 5 9. Property Designation (Lease Number): 10. Field/Pool(s): FEE-CIRI, C-061505 Ninilchik Field / Beluga-Tyonek Gas it. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 9,600' 7,987' 7,532' 5,920'—450psi 7,532' N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 91' 20" 91' 91' - 1,500 psi Surface 1,630' 9-5/8" 1,630' 1,298' 5,750 psi 3,090 psi Intermediate 4,788' T. 4,788' 3,219' 7,240 psi 5,410 psi Production Liner 5,026' 4-1/2" 9,595' 7,982' 8,930 psi 7,500 psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: 2-3/8" Tubing Grade: 4.74A / L-80 Tubing MD (ft): 5,106' See Attached Schematic See Attached Schematic 4-1/2" 12.6# / L-80 4,569' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): ZXP Liner Packer; WL Pkr / SSSV - N/A Packer 4,569' (MD) 3,028' (TVD); 5,090' MD / 3,498' TVD / SSSV - N/A 12. Attachments: Proposal Summary ❑✓ Wellbore schematic Q 13. Well Class after proposed work: - Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development ❑Z Service ❑ 14. Estimated Date for 15. Well Status after proposed work: CommencingOperations: October 1, 2018 P OIL WIND WDSPL ❑ ❑ ❑ Suspended ❑ GAS ❑✓ WAG ❑ GSTOR [I SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Chad Helgeson 777-8405 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkramer@hilco .com Contact Phone: 777-8420 Authorized Signature: Date: `7 /F COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: /, i7 I UX n — r L•IJ /t `f 5 Plug Integrity F1 BOP Test ❑ Mechanical Integrity Test E] Location Clearance ❑ Other: RBDMS�L�CT D 31018 Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No Subsequent Form Required: / v APPROVED BY Approved by: � � COMMISSIONER THE COMMISSION Date: 10 f' ��+ ��/, � �] ��/ ` II G A /1 �- 9- /43 �� Submit Form and Form 10-403 Revised 4Y2077 Appr ved application is valid r -I h approval. 9��J,��(Ayachments in Duplicate L I H Hilmro Al.ek.. LU Capillary String Well: SD -05 Date: 9/18/2018 Well Name: SD -05 API Number: 50-133-20562-00 Current Status: Online Gas Well Leg: N/A Estimated Start Date: 10/1/18 Rig: NA Reg. Approval Req'd? Yes Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 206-088 First Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (M) Second Call Engineer: Chad Helgeson (907) 777-8405 (0) (907) 229-4824 (M) AFE Number: Current Surface Pressure: 55 psi Maximum Expected BHP: 500 psi @ 3,600' TVD Max. Potential Surface Pressure: 450 psi (Based on actual shut in WHP) Brief Well Summary SD -05 was drilled as a grassroots well to target gas sands in the Tyonek formations in 2006. The well was initially completed in the Tyonek. The patches across the Tyonek intervals (5,735'-5,735' and 8,270'-8,276' md) were set in 2006. A coil tubing cement plug was set from 9,325' to 8,090' and in 2007. In 2007 the Beluga 135 zone was perforated. In 2013 the Beluga 130 and 132 sands were perforated. In November of 2016, a 2-3/8" velocity string was installed in the well to a depth of 5,106'. The purpose of this work/sundry is to run a capillary line inside of the 2-3/8" tubing to infect soap to help lift the well. Capstring Procedure: 1. MIRU Cap String Truck, PT lubricator to 2,500 psi Hi 250 Low. 2. Install wellhead packoff. a. Current tree cap is 2-1/16" Otis w/ a 6-1/2 Otis Quick Union connection. 3. PU 3/8" capillary string. RIH and set @ 5,100' 4. Set spool of remaining line near well. 5. Rig down Cap String Truck. f- 6. Turn well over to production. Attachments: 1. Actual Schematic 2. Proposed Schematic H llileuru Aluskn, LLC RIB: MSL =156' 121' AGL 12 PBTD=7,537 TD=9,690' MAX HOLE ANGLE = 61.50 @ 1,434' SCHEMATIC CASING DETAIL Ninilchik Field Well #: Susan Dionne 05 Last Completed: 8/7/2006 Size Type Wt/ Grade/ Conn ID I Top Btm CMT Top 20" Conductor 133#/K-55/PE 18.73" Surf 91' 4,569' 9-5/8" Surface 40#/L-80/BTC 8.835" Surf 1,630' 12ppg/ Surface 7" Intermediate 26#/L-80/BTC 6.276" Surf 4,788' Surface 4-1/2" Liner 12.6# / L-80 / Hydril 563 3.958" 4,569' 9,595' 2.985" TUBING DETAIL 4-1/2" Tubing 12.6#/1--80/Buttress Mod 3.958" Surf 4,569' 1 2-3/8" Velocity String 4.7#/L-80/8Rnd EUE 1.995" Surf 5,106' 4,569' JEWELRY DETAIL No Depth Length ID OD Item 1 2,382 130 3.858" 5.93" Baker Chemical Injection Nipple 2 4,569' 9.55' Open 130 ZXP Liner Packer w/ 15' Teback Extension 3 4,609' 7.97' 10 2/20/13 Flex Lock Liner Hanger 4 5,040' 3.72' 1.875" 3.248" HAL XD Sliding Sleeve (X nipple profile at top of sleeve) 5 5,089' 1.53' 1.921" 2.985" Ratch Latch w/ seal assembly 6 5,090' 2.53' 1.905" 3.75" WL Set Perma-Series Pkr 7 5,098' 1.28' 1.875" 2.72" 2-3/8" X Nipple 8 5,106' 0.45 1995-. 3.52" WLEG 96,984- Squeezed & Casing Patched 4' 8,508' 8,524' PAC Valve 10 9,467' 5/31/08 Squeezed 1-40 Landing Collar 11 9,509' 7,676' 26' 5/31/08 Float Collar 12 9,593' Float Shoe PERFORATION DETAIL ne (Mp) Btm (MD) Top (TVD) Btm (TVD) FT Date Status 130 5,163' 5,173' 3,567' 3,576' 10 2/21/13 Open 130 5,251' 5,253' 3,650' 3,652' 10 2/20/13 Open .132 5,247' 5,257' 3,647' 3,656' 10 2/21/13 Open 135 5,317' 5,343' 3,714' 3,739' 26' 6/7/07 Open nek 5,735' 5,737' 4,123' 4,125' 2' 10/26/06 Squeezed & Casing Patched 65 8,270' 8,276' 6,657' 6,663' 6' 10/24/06 Squeezed & Casing Patched 83 8,508' 8,524' 6,895' 6,911' 16' 5/31/08 Squeezed 1-40 9,263' 9,289' 7,650' 7,676' 26' 5/31/08 Squeezed OPEN HOLE / CEMENT DETAIL 9-5/8" 12-1/4" hole, Cmt w/ 404 sks (180 bbls)12 ppg Type 1 cmt with 30 bbls, 12 ppg cmt to surface. (with partial lost returns) 8-1/2" hole, Cmt w/ 254 sks (111.7 bbls) 12.5 ppg type G Lead, plus 197 sks (40.9 bbls) 15.8 7" ppg type G Tail. Bump plug, 15 bbls contaminated with 5 bbls cmt to surface, 100% returns, floats held. 7" hole, Cmt w/ 20 bbl 10.5 ppg spacer followed by 330 sks (118.6 bbls) 13.0 ppg 8,045' KB cmt top from CBL run 8/7/2006. Lost circ w/83 bbls cmt displaced. PAC valve opened and 4-1/2" immediately closed. Perfed 5,735'- 5,737' (Owen 3-3/8" 6 spf) to cmt above 120 sks (43 bbls) 13.0 ppg Lead followed by 50 sks (10 bbls) 15.8 ppg Tail 7.6 bbls cmt returns to surface. INCLINATION DETAIL KOP @ 200' MD/TVD Build 5.0 deg/100' from 200-1434' MD Hold 61.5 deg from 1434-2700' MD Drop 2 deg/300' to 5900' MD Hold 1.0 deg from 5900'to TO at 9,600' MD Azimuth: 220.7 deg. Updated by DMA 09-18-18 K euro Alaeke.I.LC RI®: MSL =156' /2i' AGL PROPOSED SCHEMATIC CASING DETAIL Ninilchik Field Well #: Susan Dionne 05 Last Completed: 8/7/2006 M CMT Top 1' 30' 12ppg/ Surface 88' Surface 95' 69' 06' pple iack Extension pie profile at top y Status Open Open Open Open Squeezed & Casing Patched Squeezed & Casing Patched Squeezed Squeezed Is, 12 ppg curt to surface. 7 sks (40.9 bbls) 15.8 surface, 100% returns, ;)13.0 ppg 8,045' KB curt ilve opened and above 120 sks (43 bbis) turns to surface. Updated by DMA 09-18-18 • • zoo c6 Seth Nolan Hilcorp Alaska, LLC Z$ O GeoTech 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tele: 907 777-8308 Hilrnrp;tlaska,LIR: RECEIVED Fax: 907 777-8510 E-mail: snolan@hilcorp.com MAR 0 9 2017 DATE 03/07/17 HAOGCC o^^� DATA LOGGED h3i2o17 To: Alaska Oil & Gas Conservation Commission K.BENDER Makana Bender Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL SD 05 Prints Prints: Production Profile GR/CCL/PRES/TEMP/GRADIO/ILS/CAL/SPIN/DEFT CD : DLIS Data 2/27/2017 4:32 PM File folder LAS Data 2/27/2017 4:32 PM File folder Log 2/27/2017 4:32 PM File folder Please include current contact information if different from above. SCAMS) APR 0 7 2002 Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: ✓d��%�t� Date: • C\%,c� •th Nolan Hilcorp Alaska, LLC 1eoTech 3800 Centerpoint Drive, Suite 100 RCEIVED Anchorage, ag , AK 83083 Tele:H&iffy tI i.L i.I.d.i Fax: 907 777-8510 FEB 15 2017 E-mail: snolan@hilcorp.com AOGCC DATE 02/14/16 DATA LOGGED Z./a/2017 K BENDER To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL SD 05 Prints Same JUN 3 02011, Prints: Packer Setting Record CD : j SD-05_PACKER_16NOV16_LAS.zip 1/18/2017 1:20 PM Compressed(zippe... 231(8 SD-05_PACKER_16NOV16.pdf 1{18/2017 1:15 PM PDF Document 558 KB dJ SD-05_PACKER_16NOV16_img.tif 1/18/2017 1:1.5 PM TIF File 1498 KB Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Receive%�,y� ,^ Date: • 672‘1E I" STATE OF ALASKA A OIL AND GAS CONSERVATION COM SION JIRE ( 01 REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon II Plug Perforations M Fracture Stimulate II Pull Tubing U Operations shutdown MI Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ srforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: Run V-String ❑., 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development Q Exploratory ❑ 206-088 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic Service ❑ 6.API Number: Anchorage,AK 99503 50-133-20562-00-00 7.Property Designation(Lease Number): 8.Well Name and Number: FEE-CIRI;C-061505 Ninilchik Unit S Dionne 5 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Ninilchik Field/Beluga-Tyonek Gas 11.Present Well Condition Summary: Total Depth measured 9,600 feet Plugs measured 7,532 feet true vertical 7,987 feet Junk measured N/A feet Effective Depth measured 7,532 feet Packer measured 4,569;5,090 feet true vertical 5,920 feet true vertical 3,028;3,498 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 91' 20" 91' 91' 3,060psi 1,500psi Surface 1,630' 9-5/8" 1,630' 1,298' 5,750psi 3,090psi Intermediate 4,788' 7" 4,788' 3,219' 7,240psi 5,410psi Production Liner 5,026' 4-1/2" 9,595' 7,982' 8,930psi 7,500psi Perforation depth Measured depth See Attached Schematic 'SCANNED IA 1A " 0 LTJ ? True Vertical depth See Attached Schematic 4-1/2" 12.6#/L-80 4,569'MD 4,569'TVD Tubing(size,grade,measured and true vertical depth) VS 2-3/8" 4.7#/L-80 5,106'MD 3,513'ND ZXP Liner Pkr; 4,569'MD 3,028'ND Packers and SSSV(type,measured and true vertical depth) WL Pkr;N/A 5,090'MD 3,498'ND N/A;N/A 12.Stimulation or cement squeeze summary: N/A Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 1678 98 104 52 Subsequent to operation: o 889 60 300 45 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations CI Exploratory❑ Development 0 Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil ❑ Gas Q WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: #316-554 Contact Taylor Wellman-777-8449 Z't6d Email twellmaniahilcorp.com---r-4/ Printed Name Chad Helgeson Title Operations Manager Signature ,.� f 1 Phone 907-777-8405 Date (Z/J//‘, Form 10-404 Revised 5/2015 /1,-13-14 /i /LX N/(,(� // R:DMS Lu DEC - 8 2016 Submit Original Only • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date SD-05 =4.t i 50-133-20562-00 206-088 11/9/16 11/28/16 Daily Operations: 11/09/2016-Wednesday Sign in, PTW and JSA with Halliburton and Tri-Point. Spotted and rig up lubricator and make up Tri Point packer. Pressure tested to 250 psi low and 2,500 psi high. Bled pressure off lubricator and tried to run in hole. Tools would not move.TP- 220 psi. Packer is either set or something has it hung up in Lub. To set packer it takes 1,200 psi and 30K to shear it. Called town and discussed. Got cold tap from Halliburton coming out and ordered man lift from United Rental. Had another JSA on how we would deal with pressure above packer if any and laying lub down. Man lift arrived. We then determined that there was no pressure on well and no pressure above packer. Closed tool trap and lay down lubricator with wireline following down with tool weight on line. Determined packer was partially set. Pulled packer assy out lubricator. Broke assy down. Rig down eline lub and secured well. Setting tool had stroked. 11/16/2016-Wednesday Sign in. PTW and JSA. Rig up lubricator. PT to 250 psi low and 2,500 psi high.TP-300 psi. RIH with 3.79" OD 4-1/2" x 2- 3/8" packer and tie into CBL log. Ran correlation log and send to town. Get ok to set top of packer at 5,074'that put WLRG at 5,090'. Spot packer at 5,074' and set packer with 300 psi on tubing. Lost 200 lbs line wt when packer set. Pick up 30' and go back down and tag lightly. POOH. Setting tool looked good. Rig down lubricator and turn well back over to field. 11/17/2016-Thursday Line up flowline to test separator. Initial tubing pressure= 270psi. Open well to compression pressure,tubing pressure drop to 40psi. Isolate well from production. Bleed tubing through 1/2" high pressure hose to bleed tank to Opsi. Monitor tubing pressure. Opsi build up in 4 hours. Good packer and plug set. Line up to load with KCI. Begin mixing and loading down tubing. Load 50bbls down tubing. 11/20/2016-Sunday Load tbg w/30bbls of 3% KCI. MIT-T to 1,580psi- Passed. RU barton chart recorder. Initial tbg pressure= 1,580psi, 15 min pressure= 1,580psi, 30 min pressure= 1,580psi. Bleed down tubing pressure and RD. 11/21/2016- Monday Held PJSM at Moncla office. Mobe 401 WOR and associated equipment to SD-5. Off loaded equipment. Laid containment and spotted beam and WOR. SDFN. 11/22/2016-Tuesday Held PJSM and site orientation. Continued RU Moncla 401 and associated equipment. Spotted manifold, pit, pump, heater and Gen building. Raised derrick and securedirig. MU circulating lines to pit, pump and manifold. Winterized circulating lines and pit area. Covered drill console and draw works. Laid out Koomey lines and kill/ck lines. Set BPV and ND production tree. Pulled BPV. NU 11" 5M x 7-1/16"tubing head with 4" TWC in place. NU 7-1/16" 5M BOP's (7-1/16" 5M mud cross w/two 2-1/16" 5M manual valve and two 2-1/16" HCR valves, 7-1/16" 5M double gate w/blinds on bottom and 2-3/8" to 3-1/2"VBR's on top, 7-1/16" 5M annular preventer. RU floor.Winterized BOP stack and ran heat to all BOPE. MU kill/ck Lines from BOP stack to manifolds. SDFN. Night rig watch and tower. • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date SD-05 50-133-20562-00 206-088 11/9/16 11/28/16 Daily Operations: 11/23/2016-Wednesday Held PJSM and discussed daily activities. RU the handrails and stairwell. MU kill/CK lines and winterized same. Connected Koomey lines and fuctioned BOP's. Loaded pit with 5bbls of water to circulate thru the stack, lines and manifold. Finished all winterization for rig and associated equipment. Set catwalk and pipe racks. Racked 100 jts of 2- 3/8"4.7# EUE L-80 8rd and tallied same. PU/MU 2-3/8"test jt. Flooded BOPE, circulated and purged. Pressured up on BOPE to 2,500psi and held for 5mins,good shell test.Tested_3QPE peLAOGCCregs as follows: gas detection, pressure tested annular 250-2,500psi, rams 250-2,500psi, valves 250-2,500psi. Performed Koomey drawdown test. No failures recorded.AOGCC witnessed waived by Jim Regg on 11/21/16 at 15:21 hrs. Pulled 7"test plug, secured well and SDFN. Night rig watch on tower. 11/24/2016-Thursday Held PJSM and discussed daily activities. Repaired step on stairwell, RU trash pump to pump displaced fluid while tripping completion in the hole. RU tongs and handling tools for 2-3/8"tbg. Heading up tread protectors on tbg for easy removal.TIH w/2-3/8" completion string to 5,050'and established parameters up-weight 20K/dn-weight 18K. SO and tagged packer @ 5,069' pipe measurements. Set down 10K and PU 10K over to ensure latch. SO to neutral weight and marked pipe for space out. Made 10 turns to the right and released latch assembly. L/D tag jt and PU/MU 10', 6', 2' pup and tbg hanger. MU Landing jt and landed tbg with 17K on hanger. RILDS. Completion depth as following: Latch assembly w/seals @ 5,088', 2.375"4.7#EUE L-80 8rd pup, 1 it 2.375"4.7#EUE L-80 8rd, 2.375" 4.7#EUE L-80 8rd pup, sliding sleeve @ 5,040', 2.375"4.7# EUE L-80 8rd pup, 153 It 2.375"4.7# EUE L-80 8rd, 10' 2.375" 4.7# EUE L-80 8rd pup, 6' 2.375"4.7# EUE L-80 8rd pup, 2' 2.375"4.7#EUE L-80 8rd pup and 7" pup hanger. Opened csg(2-3/8"x 4-1/2" annulus) and MU Kelly hose. PT tbg to 2,500psi and charted for 30mins,good test. Opened tbg and MU Kelly hose to csg (2-3/8" x 4-1/2"annulus) PT to 1,500psi and charted for 30mins,good test. BO/LD landing jt and set a BPV. Secured well and SDFN. Night watch on tower. 11/25/2016-Friday Held PJSM, discussed daily pps. Note:Weather conditions heavy snow cleared and cleaned rig floor, LD handrails, BOP skirt and stairwell. RD floor and secured to the derrick. Removed Koomey lines and kill/Ck lines from BOP Stack. ND 7- 1/16" BOP's. NU 2-1/16" production tree and orientated with csg valves.Tested to 5,000psi, Good Test. Pulled BPV and secured tree. Welder took measurement to start fab work on flowline. RD Pit, pump and manifold lines. LD derrick and loaded carrier on the low-boy and staged at the side of the pad to be hauled on 11/29. Continued RDMO Moncla 401 and associated equipment. Loaded 4 Weaver Bros'trucks and hauled to KTU 32-7. 11/26/2016-Saturday Continued RDMO Moncla 401. Cleared and cleaned pad around SD-5 well head. Well to production. • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date SD-05 50-133-20562-00 206-088 11/9/16 11/28/16 Daily Operations: 11/27/2016-Sunday Held PJSM, MIRU Pollard SL unit, PT lube to 250 psi low/2,500 psi high. RIH w/BO shifting set down at hanger and couldn't work thru. Pumped 10 gals of methanol and let soak. Worked tool thru and RIH set down at 1,400'and couldn't go deeper. POOH, PU roller stems and RIH to same. Worked down hole from 900'to sliding sleeve @ 5,035'SLM. Could not latch. POOH. RIH w/the BO shifting tool (positive keys)and roller stem. Latched sliding sleeve at 5,035'.Jarred up and opened sleeve. POOH. RU Tri-plex and circulated well to ensure sleeve was opened. MIRU SLB N2 pump truck. Hooked-up iron to 2-3/8"x 4-1/2" annulus and tested to 3,500psi. Hooked-up flow back irin from tbg wing to 50bbl open top tank. Opened well and pumped 950 scfm at 1,250psi down annulus and returns up tbg.Total returns of 60bbls. SD Pump and SI well. RDMO N2 pump truck. Secured well and SDFN. 11/28/2016- Monday RU and PT lube to 250psi low/2,500psi high. Shift SSD down (closed). Verify by bleed tubing down T/I pressures = 600/1,100psi. RIH w/2"JDC and pull prong from 5,087' KB. RIH w/2-3/8" GS and pull plug from 5,096' KB. RD SL unit. F • • Ninilchik Field SCHEMATIC Well#:Susan Dionne 05 EliEawrp Alaska,LEALast Completed:8/7/2006 RKB:MSL=156'/21'AGL 4.4 � t CASING DETAIL Size Type Wt/Grade/Conn ID Top Btm CMT Top 20" Conductor 133#/K-55/PE 18.73" Surf 91 za' } 9 5/8" Surface 40#/L-80/BTC 8.835" Surf 1,630' 12ppg/ Surface 7" Intermediate 26#/L-80/BTC 6.276" Surf 4,788' Surface 4-1/2" Liner 12.64/L-80/Hydril 563 3.958" 4,569' 9,595' TUBING DETAIL 1 4-1/2" Tubing 12.6#/L-80/Buttress Mod 3.958" Surf 4,569' 9_s/g,A 2-3/8" Velocity String 4.7#/L-80/8Rnd EUE 1.995" Surf 5,106' JEWELRY DETAIL No Depth Length ID OD Item 1 2,382 3.858" 5.93" Baker Chemical Injection Nipple ¶ 2 4,569' 9.55' ZXP Liner Packer w/15'Tieback Extension r 11 t 3 4,609' 7.97' Flex Lock Liner Hanger 4 5,040' 3.72' 1.875" 3.248" HAL XD Sliding Sleeve 5 5,089' 1.53' 1.921" 2.985" Ratch Latch w/seal assembly 6 5,090' 2.53' 1.905" 3.75" WL Set Perma-Series Pkr 7 5,098' 1.28' 1.875" 2.72" 2-3/8"X Nipple 8 5,106' 0.45' 1.995" 3.52" WLEG 9 6,984' 4' PAC Valve 10 9,467' Landing Collar 11 9,509' Float Collar 12 9,593' Float Shoe PERFORATION DETAIL [ Zone (MD) Btm(MD) Top(TVD) Btm(ND) FT Date Status BLG-130 5,163' 5,173' 3,567' 3,576' 10 2/21/13 Open ' X 2 BLG-130 5,251' 5,253' 3,650' 3,652' 10 2/20/13 Open tib 3 BLG-132 5,247' 5,257' 3,647' 3,656' 10 2/21/13 Open L BLG-135 5,317' 5,343' 3,714' 3,739' 26' 6/7/07 Open Tyonek 5,735' 5,737' 4,123' 4,125' 2' 10/26/06 Squeezed&Casing Patched 7- T-65 8,270' 8,276' 6,657' 6,663' 6' 10/24/06 Squeezed&Casing Patched T-83 8,508' 8,524' 6,895' 6,911' 16' 5/31/08 Squeezed ME a T-140 9,263' 9,289' 7,650' 7,676' 26' 5/31/08 Squeezed MB 7 a e- OPEN HOLE/CEMENT DETAIL 9-5/8" 12-1/4"hole,Cmt w/404 sks(180 bbls)12 ppg Type 1 cmt with 30 bbls,12 ppg cmt to surface. 9 (with partial lost returns) TOC tagged @ 8-1/2"hole,Cmt w/254 sks(111.7 bbls)12.5 ppg type G Lead,plus 197 sks(40.9 bbls)15.8 7,532'MD 7" ppg type G Tail. Bump plug,15 bbls contaminated with 5 bbls cmt to surface,100%returns, on8/30/2010 floats held. L 7"hole,Cmt w/20 bbl 10.5 ppg spacer followed by 330 sks(118.6 bbls)13.0 ppg 8,045'KB cmt 4-1/2" top from CBL run 8/7/2006. Lost circ w/83 bbls cmt displaced. PAC valve opened and immediately closed. Perfed 5,735'-5,737'(Owen 3-3/8"6 spf)to cmt above 120 sks(43 bbls) 13.0 ppg Lead followed by 50 sks(10 bbls)15.8 ppg Tail 7.6 bbls cmt returns to surface. TOC tagged @ 9,341'DM «,5/31/200710 INCLINATION DETAIL a-1/r' 11 KOP @ 200'MD/TVD ' i2 Build 5.0 deg/100'from 200-1434'MD PBTD x,007' TD=9,600' Hold 61.5 deg from 1434-2700'MD Drop 2 deg/100'to 5900'MD MAX HOLE ANGLE=61.5°(til 1,434' Hold 1.0 deg from 5900'to TD at 9,600'MD Azimuth:220.7 deg. Updated by 1W 12-07-16 •VOF Ty • ,\\V/7,,'s THE STATE Alaska Oil and Gas f OQ T A sConservation Commission 1 1L t � 333 West Seventh Avenue k. }£ .> GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 (4' SlP Fax: 907.276.7542 www.aogcc.alaska.gov Chad Helgeson Operations Manager SCANNED FEB 2 8 2017 Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Ninilchik Field, Beluga/Tyonek Gas Pool,NU S Dionne 5 Permit to Drill Number: 206-088 Sundry Number: 316-554 Dear Mr. Helgeson: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy P Foerster Chair DATED this Z day of November, 2016. RBDMS i - NUV - 7 2016 • • '.... 4'4,, ,,,P AL a.OW%M.. STATE OF ALASKA DC j 2 6 2016 • ALASKA OIL AND GAS CONSERVATION COMMISSION I3-r s l l -1,,J, APPLICATION FOR SUNDRY APPROVALS 1 �' 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate 0 Repair Well ❑ Operations shutdown 0 Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other. Run V-String 0 2.Operator Name: Hilcorp Alaska,LLC 4.Current Well Class: 5.Permit to Drill Number. Exploratory 0 Development ❑✓ • 206-088 • 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number. Anchorage,Alaska 99503 50-133-20562-00-00• 7.If perforating: [I v, 7�44 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? 20_69.G2Cr55ta)-(4) ) Ninilchik Unit S Dionne 5 ' Will planned perforations require a spacing exception? Yes El No Q 9.Property Designation(Lease Number): 10.Field/Pool(s): 6C l� . 7;o-7-t 4' 4.1-4—' FEE-CI RI • C'—(jr,r9Zy‘,7--, "ztxi/. Ninilchik Field/,SePridetf a ug as • rd6 ,,,,.--,e.,,, 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 9,600' 7,987' 7,532' 5,920' 450 psi ' 7,532' N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 91' 20" 91' 91' - 1,500 psi Surface 1,630' 9-5/8" 1,630' 1,298' 5,750 psi 3,090 psi Intermediate 4,788' 7" 4,788' 3,219' 7,240 psi 5,410 psi Production Liner 5,026' 4-1/2" 9,595' 7,982' 8,930 psi 7,500 psi Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 4-1/2" 12.6#/L-80 4,569' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): ZXP Liner Packer/SSSV-N/A Packer 4,569'(MD)3,028'(TVD)/SSSV-N/A 12.Attachments: Proposal Summary Q Wellbore schematic ❑✓ 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑✓ Exploratory ❑ Stratigraphic ❑ Development 0 • Service ❑ 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: November 7,2016 OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS ❑., . WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Taylor Wellman-777-8449 Email twellmap hilcorp.gom Printed Name Chad Helgeson Title 9 Operations Manager / Signature � ' `�� Phone 907-777-8405 Date /0/e SP{, COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. Plug Integrity ❑ BOP Test II Mechanicalc� Integrity Test ❑ Location Clearance CI Other: 2_5CIa r�,�z LL)! le- /•r. Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ Nod Subsequent Form Required: ;4cF o.IL ilial COY—`� RBDMS t t NUS - 7 2016 P APPROVED BY Approved by: ''� COMMISSIONER THE COMMISSION Date:/l— C—I 8'r/ � Submit Form and Form 10-403 Revise' to .31./0 d 11/2015 v C id for 12 months fro the date o�pproVal. Attachments in Duplicate -i- � /v.2£3./4 • • RWO Well: SD-05 Maori)Alaska,LL Date: 10/21/2016 Well Name: SD-05 API Number: 50-133-20562-00 Current Status: Online Gas Well Leg: N/A Estimated Start Date: 11/07/16 Rig: Moncla 401 Reg.Approval Req'd? Yes Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 206-088 First Call Engineer: Taylor Wellman (907)777-8449(0) (907)947-9533 (M) Second Call Engineer: Chad Helgeson (907)777-8405 (0) (907) 229-4824(M) AFE Number: Current Surface Pressure: 55 psi Maximum Expected BHP: 500 psi @ 3,600' TVD Max. Potential Surface Pressure: 450 psi •- (Based on actual shut in WHP) Brief Well Summary SD-05 was drilled as a grassroots well to target gas sands in the Tyonek formations in 2006. The well was initially completed in the Tyonek. The patches across the Tyonek intervals (5,735'-5,735' and 8,270'-8,276' md) were set in 2006. A coil tubing cement plug was set from 9,325' to 8,090' and in 2007. In 2007 the Beluga 135 zone was perforated. In 2013 the Beluga 130 and 132 sands were perforated. The well is currently producing 1.5-1.7 mmscfpd and approx. 100bbIs of water per day in a slug flow. The purpose of this work/sundry is to run 2-3/8"tubing to increase rate and minimize slugging. Safety Concerns • Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter, i.e. near flow-back tank. • Consider tank placement based on wind direction and current weather forecast (venting methane and Nitrogen during this job) • Ensure all crews are aware of stop job authority Pre-Sundry Operations Slickline Procedure: 1. Coordinate with production to shut in the well prior to rig up to allow settling of any sand/fines. 2. MIRU Slickline, pressure test lubricator to 250psi low and 2500psi high. 3. MU 3.75"gauge ring toolstring and drift past 5100' md. 4. MU brush and make multiple passes past 4500'to clear sand/well fines from the s-shaped portion of the tubing. 5. MU dummy packer drift assembly and drift to+/-5100' md. a. Packer setting depth is+/-5060' md. b. Packer&tubing tail assembly dimensions: OAL= 19',OD=3.75". See packer schematic for full details. c. Results of the drift will determine if E-Line or Coil Tubing will be used to deploy the packer. Sundried Operations–All operations beyond this point will require the approved sundry . E-Line Procedure: 6. MIRU E-Line unit. Pressure test to 250psi low/2500psi high. 7. MU 4-1/2"x2-3/8" Packer toolstring. a. Packer dimensions:OAL=4', Max OD=3.75" b. Ensure the 2-3/8"X-rfai and prong(extended)are in the X Nipple of the tubing tail prior to deployment. 8. RIH and set packer at+/-5,060' md. POOH. • S RWO • Well: SD-05 Hilcorp Alaska,LL Date:10/21/2016 a. Reference Log: Expro CBL dated 08-25-06 9. Use an adjacent well to pressure tubing up to^'300psi to ensure good packer set and plug is holding. Coil Tubing Procedure Contingenc if Slickline is unable to freely drift past the s-shaped deviation to packer setting depth 1. Submit 24 hr.witness notification to AOGCC via web base notification. 2. MIRU Coiled Tubing, PT BOPE to 250/3500 psi. 3. RIH w/1.5"coil w/3.75" drift and jet nozzle to tag casing patch @ 5,733' md. a. Minimum target depth to achieve is 5120' md. 4. MU and RIH w/2-3/8"x4-1/2" packer assembly. Set packer at+/-5,060' md. 5. POOH and RD CT unit. Pumping Procedure 10. Load tubing with 3%KCI. a. 4-1/2"Tubing volume to X-Nipple 0.0152bpf x 5080')= 77.3bbls 11. Pressure test the tubing to 1500psi. 12. Bleed down tubing pressure to Opsi upon test completion. WO Rig Procedure: 6. MIRU Moncla#401 WO Rig. 7. Confirm tubing pressure is Opsi. 8. Set 4" BIN, ND Tree. — - " 131' J J 9. NU 11" 5M x 7-1/16" 5M tubing head,test hanger void to 5000psi. Install casing valves to the new r� tubing head. '7 Y c:cs.) ZSL p 10. NU 7" BOPE. Sct T_test{plug.Test to 250 psi Low/ psi High, annular to 250 psi Low/1,500 psi High (hold each valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Notify AOGCC 24 hrs in advance of BOP test. b. Test VBR rams on 2-3/8"test joint. 11. Bleed any pressure off tubing. P . Pull 4" BPV. = Bb- `-1 a. If pressure will not bleed off, contact Ops Engineer for discussion prior&pumping any additional 8.5 ppg 3%KCI. 12. MU completion per the proposed schematic,consisting of: a. 2-3/8" seal assembly , b. 2-3/8" pup joint c. 2-3/8"tubing joint d. 2-3/8" pup joint e. 2-3/8" Sliding Sleeve i. Ensure sliding sleeve is drifted for the 2-3/8"x plug to be pulled from the x nipple @ +/-5070' md. f. 2-3/8" pup joint g. 2-3/8"tubing to surface 13. RIH with 2-3/8"completion to just above the packer. 14. Obtain accurate pick-up and slack-off weights and record same. 15. Slowly lower seal assembly into the packer sealbore. Monitor weight indicator. 16. Slack off until you begin to take weight and stop. 17. Pick up to "pick-up" weight and stop. 18. Rig up pump in sub, close annular preventer and apply annulus pressure. 19. Release pressure on preventer and mark tubing. Pick up and space out latch into packer anchor and d tubing in g land the hanger at neutral. a • RWO • Well: SD-05 Hilcoru Alaska,LL, Date:10/21/2016 20. Pressure test the tubing to 2,500psi for 30 min. 21. Pressure test the 2-3/8"x4-1/2"annulus to 1500psi for 30 min. 22. Set BPV. ND BOPE. NU 2-1/16" 5M tree. Pull BPV. 23. Set TWC.Test tubing hanger and tree to 250/5,000 psi. Pull TWC. 24. RD Moncla#401 WO Rig. 25. Replace IA x OA pressure gauge if removed (7"x9-5/8")and (9-5/8"x20"). Slickline Procedure: 26. MIRU Slickline, Pressure test to 250psi low/2500psi high. ' IVO 3 cop 27. Make gauge ring run to+/-5070' md. 28. RIH and shift the 2-3/8"sliding sleeve open @+/-5020' md. 04. 4-? 29. Use a triplex to pump down the 2-3/8"x4-1/2" annulus to confirm sliding sleeve is open. 30. RD Slickline. N2 Pumping 31. RU N2 pumping unit to the 2-3/8"x4-1/2"casing valve. 32. Pressure test connections to 3500psi. 33. Begin to pump N2 down 2-3/8"x4-1/2"while taking returns up the 2-3/8"tubing. a. 2-3/8"x4-1/2" annulus volume to sliding sleeve(0.00974bpf x 5020')=49bbls b. 2-3/8",4.7#tbg volume to sliding sleeve (0.00387bpf x 5020')= 20bbls 34. Once liquid returns stop coming to surface, close wing valve and shut down pump. a. Minimum volume of fluid returns before shutting down is 50bbls. b. 2-3/8"x4-1/2" annulus pressure should be higher than the 2-3/8"tbg: i. Tbg FL @ surface, 2-3/8"x4-1/2"annulus-1300psi higher ✓ ii. TbgFL 1500' and 2-3/8"x4-1/2" annulus-900psi higher @p g iii. Tbg FL @ 3000' md, 2-3/8"x4-1/2" annulus"S50psi higher iv. Tbg FL @ 5000' md, 2-3/8"x4-1/2" annulus equal pressure 35. RD N2 pumping unit. Slickline Procedure: 36. MIRU Slickline, Pressure test to 250psi low/2500psi high. 37. RIH and shift the 2-3/8"sliding sleeve closed @+/-5020' md. a. Bleed 100psi off the 2-3/8"x4-1/2" annulus and check tubing pressure for response to confirm sliding sleeve is closed. b. Bleed the tubing down to 0 psi. 38. If needed, MU swabbing toolstring and remove as much brine as possible from the well. 39. Pull prong from plug @ +/-5,069' md. 40. Pull plug body from x nipple @ +/-5,069' md. 41. RD Slickline and hand well over to production. Attachments: 1. Actual Schematic 2. Proposed Schematic 3. Actual Wellhead Diagram 4. Proposed Wellhead Diagram 5. Moncla 401 BOPE Schematic 6. CT BOPE Schematic 7. CT Schematic(forward jetting) 8. Blank RWO Procedure Change Form • • Ninilchik Field .11 SCHEMATIC Well #: Susan Dionne 05 Hileorp Alaska,LLC Last Corn Dleted: 8/7/2006 CASING DETAIL RIO:MSL=156'121'AGL Size Type Wt/Grade/Conn ID Top Btm CMT Top 20" Conductor 1334/K-55/PE 18.73 Surf 91' 1 O. ,,,, * 12ppg/ 9 7" Surface 404/L-80/BTC 8.835 Surf 1,630' Surface q za 7" Intermediate 26#/L-80/BTC 6.276 Surf 4,788' Surface . 4-1/2" Liner 12.64/L-80/Hydril 563 3.958 4,569' 9,595' 'i?v el , TUBING DETAIL '` 4-1/2" Tubing 12.6#/L-80/Buttress Mod 3.958 Surf 4,569' 9-5/8" JEWELRY DETAIL t No Depth Length ID OD Item 1 2,382 3.858 5.93 Baker Chemical Injection Nipple Li4; 1 4,569' 9.55 ZXP Liner Packer w/15'Tieback Extension 1 3 4,609' 7.97 Flex Lock Liner Hanger 4 6,984' 4 PAC Valve 5 9,467' Landing Collar ' 6 9,509' Float Collar g; ° 7 9,593' Float Shoe ? PERFORATION DETAIL Zone (MD) Btm(MD) Top(TVD) Btm(TVD) FT Date Status - BLG-130 5,163' 5,173' 3,567' 3,576' 10 2/21/13 Open BLG-130 5,251' 5,253' 3,650' 3,652' 10 2/20/13 Open tf '221 ,J 2 BLG-132 5,247' 5,257' 3,647' 3,656' 10 2/21/13 Open . ; ., BLG-135 5,317 5,343' 3,714' 3,739' 26' 6/7/07 Open ,: _ ,, Tyonek 5,735' 5,737' 4,123' 4,125' 2' 10/26/06 Squeezed&Casing Patched ;Lit PI l_ T-65 8,270' 8,276' 6,657' 6,663' 6' 10/24/06 Squeezed&Casing Patched 7' A,"�i ,i.1 11 - T-83 8,508' 8,524' 6,895' 6,911' 16' 5/31/08 Squeezed ,. 1-140 9,263' 9,289' 7,650' 7,676' 26' 5/31/08 Squeezed OPEN HOLE/CEMENT DETAIL ( y, , v 4 9 5/8„ 12-1/4" hole, Cmt w/404 sks(180 bbls)12 ppg Type 1 cmt with 30 bbls,12 ppg cmt to " : surface. (with partial lost returns) TOC tagged@ + ,41 8-1/2" hole, Cmt w/254 sks(111.7 bbls)12.5 ppg type G Lead,plus 197 sks(40.9 bbls)15.8 7,532'Mo ,. 7" ppg type G Tail. Bump plug,15 bbls contaminated with 5 bbls cmt to surface,100%returns, on 8/30/201 %0 '" floats held. 1510 7"hole,Cmt w/20 bbl 10.5 ppg spacer followed by 330 sks(118.6 bbls)13.0 ppg 8,045'KB cmt y 4-1/2" top from CBL run 8/7/2006. Lost circ w/83 bbls cmt displaced. PAC valve opened and ,f 4 immediately closed. Perfed 5,735'-5,737'(Owen 3-3/8"6 spf)to cmt above 120 sks(43 bbls) . 13.0 ppg Lead followed by 50 sks(10 bbls)15.8 ppg Tail 7.6 bbls cmt returns to surface. TOC tagged@ " •' INCLINATION DETAIL 9,341'CTM " on 5/31/2C07 - 5 KOP @ 200'MD/TVD �, t* 6 Build 5.0 deg/100'from 200-1434'MD 41/2 7 Hold 61.5 deg from 1434-2700'MD PBTD43,007' TD=9,600' Drop 2 deg/100'to 5900'MD MAX HOLE ANGLE=61.5°a 1,,434' Hold 1:0 deg from 5900'to TD at 9,600'MD Azimuth:220.7 deg. Revised By:TDF 5/9/2013 . . • Ninilchik Field PROPOSED SCHEMATIC Well #: Susan Dionne 05 Hilcorp Alaska,LLC Last Completed: 8/7/2006 CASING DETAIL Rica MSL=156'/21'PGL Size Type Wt/Grade/Conn ID Top Btm CMT Top 0 } � 20" Conductor 133#/K-55/PE 18.73 Surf 91' N 9-5/8 " Surface 404/L-80/BTC 8.835 Surf 1,630' Su ppg/ r 2a v 4 7" Intermediate 26#/L-80/BTC 6.276 Surf 4,788' Surface 44t 1 ti a^ $ :• 1 4-1 /2" Liner 12.6#/L-80/Hydril 563 3.958 4,569' 9,595' 4 ? I ¢ TUBING DETAIL 1 4-1/2" Tubing 12.6#/L-80/Buttress Mod 3.958 Surf 4,569' 950 ) 2-3/8" Velocity String 4.7#/L-80/8Rnd EUE 1.995 Surf +/-5,092' s i +„ it JEWELRY DETAIL St ' No Depth Length ID OD Item t .' 1 2,382 3.858 5.93 Baker Chemical Injection Nipple ro r , �1' 2 4,569' 9.55 ZXP Liner Packer w/15'Tieback Extension 1 3 4,609' 7.97 Flex Lock Liner Hanger 1 * 4 +/-5,020 5 1.875 2.905 2-3/8"Sliding Sleeve /7 $ 5 +/-5,060' 4 1.905 3.75 4-1/2"X2-3/8"Pkr A14,1 0. 6 +/-5,069' 1 1.875 3.063 2-3/8"X Nipple ` 7 +/-5,082' 1 1.995 3.063 WLEG 2, t 8 6,984' 4 PAC Valve 8 ( 9 9,467' Landing Collar 4 10 9,509' Float Collar ip 7, 11 9,593' Float Shoe $ ;.'+ 2 PERFORA I ION DETAIL ;'gem �'if �� Zone (MD) Btm(MD) Top(ND) Btm(TVD) FT Date Status s"; , s ,' 3 2 BLG-130 5,163' 5,173' 3,567' 3,576' 10 2/21/13 Open r* '' BLG-130 5,251' 5,253' 3,650' 3,652' 10 2/20/13 Open 7' s '•1 S.5 BLG -132 5,247' 5,257' 3,647' 3,656' 10 2/21/13 Open BLG-135 5,317' 5,343' 3,714' 3,739' 26' 6/7/07 Open sr*1 .' Tyonek 5,735' 5,737' 4,123' 4,125' 2' 10/26/06 Squeezed&Casing Patched , 4 : 7, 6 14 1 7 T-65 8,270' 8,276' 6,657' 6,663' 6' 10/24/06 Squeezed&Casing Patched T-83 8,508' 8,524' 6,895' 6,911' 16' 5/31/08 Squeezed ,1 1 18 T-140 9,263' 9,289' 7,650' 7,676' 26' 5/31/08 Squeezed Tocta�ed@ '' a OPEN HOLE/CEMENT DETAIL 7,532'MD on8/30/2010 , " ' " 12-1/4" hole, Cmt w/404 sks(180 bbls)12 ppg Type 1 cmt with 30 bbls,12 ppg cmt to "1'' r " 9-5/8" surface. (with partial lost returns) a, , ,� 8-1/2" hole, Cmt w/254 sks(111.7 bbls)12.5 ppg type G Lead,plus 197 sks(40.9 bbls)15.8 i? Z1 7" ppg type G Tail. Bump plug,15 bbls contaminated with 5 bbls cmt to surface,100%returns, > ' , floats held. r« �� , j► 7"hole,Cmt w/20 bbl 10.5 ppg spacer followed by 330 sks(118.6 bbls)13.0 ppg 8,045'KB cmt 9.341' i g 4-1/2" top from CBL run 8/7/2006. Lost circ w/83 bbls cmt displaced. PAC valve opened and taggon5/31/2007 p 4* 9 immediately closed. Perfed 5,735'-5,737'(Owen 3-3/8"6 spf)to cmt above 120 sks(43 bbls) 'K°+ (10 13.0 ppg Lead followed by 50 sks(10 bbls)15.8 ppg Tail 7.6 bbls cmt returns to surface. 11 INCLINATION DETAIL PBTD 43,007' TD=9,600' KOP @ 200'M D/TVD MAX HOLE ANGLE=61.5°(01,434' Build 5.0 deg/100'from 200-1434'MD Hold 61.5 deg from 1434-2700'MD Drop 2 deg/100'to 5900'MD Hold 1.0 deg from 5900'to TD at 9,600'MD Revised By:TDF 5/9/2013 . Azimuth:220.7 deg. • • Ninilchik Unit SD #5 10/13/2016 II1I..'9. V:4•1.e.1.1 t. Ninilchik Unit Tubing hanger,MB-150,11 X Susan Dionne#5 4.909 MCA lift X4'A IBT susp, 20 X 9 5/8 X 7 X 4 1/2 w/4"Type H BPV profile,2- %continuous control lines 6.5"Extended neck Tree cap,Otis,4 1/16 5M FE X 6'A Otis Quick Union 0 nn iun i LOLL ��O 44\.c, QUO �`c Q<' `c� ��,Ops` Valve,Swab, Ja,,e�h�.� \,e�=t,(OVG-M,4 1/16 5M FE,HWO, Iv, ' Stiff �; Ja 3ti oQ DD trim ��C•l�Ui �• LOO' .ZP t._i iiiTiii lin '- 4 \43 +e Tee,stdd,4 1/16 5M X 11( i C441!: r/, O h ;-.-4i I iA 1111nu m Valve,upper master, � O VG-M,4 1/16 5M FE,HWO, i 110 DD trim *70 Bi i.Inn DSA,4 1/16 10M X 4 1/8 5M MIN 4 lin O OP Valve,master,VG-200, 0/ J, 41/16 10M FE,HWO,DD4�� trim w® Adapter,Vetco,11 5M stdd X -all= 4 1/16 10M stdd top, prepped f/6.5"extended -- 1 neck hanger MN Multi bowl,Vetco MB-150, -'mi1 ii I � ' "_ 11 3M stdd bottom X 11 5M FE top,w/ 2-2 1/16 SM SSO,1-control = • • Ninilchik Unit . 11 SD #5 Proposed 10/20/2016 IGlr.)rp tlai•,a.1.1A. Ninilchik Unit Tubing hanger,Cactus-C-EN, Susan Dionne#5 7 x 2 3/8 EUE 8rd w/2"type 20 X95/8X7X4YX23/8 HBPVprofile,DDmaterial, PROPOSED 5 A Extended neck Tubing hanger,MB-150,11 X 4.909 MCA lift X4'A IBT susp, w/4"Type H BPV profile,2- %continuous control lines 6.5"Extended neck Tree cap,Otis,2 1/16 5M FE X 6 14 Otis Quick Union art, �J,�`��t., Valve,Swab, ,r. co�. `p4d 4., e. WKM-M,2 1/16 5M FE, . .,„T.74 .,`4 a\,'N\Otis ,e., ,) 'GJo C. HWO, DD trim $<< 444- 'Zs O \raa .,,., 44 Valve,Wing, :'r, [-L I ■ WKM-M,2 1/16 5M FE, �� ° ! { fj'�'�} HWO, DD trim "`.)z. '12 a ��7 ' Ai'. Valve,upper master, ►,( 6, WKM-M,2 1/16 5M FE, + ' HWO, DD trim I Valve,master, WKM-M,21/16 SM FE, r� HWO, DD trims'•• Tubing head,Cactus C, 11 5M x 7 1/16 5M,w/2- �• - 2 1/16 5M SSO,btm prepped ■SII■ ._U ' i11w-11in'- f/Vetco 6.5"hanger neck t t„,,,.J - 1411 ill -IA'1( p -( ' 1 I ; 'At'Z 1! 11 : it't, ; -'r -- ' ,....-"" • ' - - ko 07 1111 • iti VI .c:1 i • fir 1 . --------_____-- ,t-- I- Multibowl,Vetco MB-150, -'- �� `\ � 11 3M stdd bottom X 115MFEtop,w/ 0 2-2 1/16 5M SSO,1-control ■.III J—,1ii iml.'= -1 7:::,,,,. , line exit " .11 ra ' i Starting head, '! ` ,■ Vetco MB-150, " ' - 11 3M X 9 5/8 VG-Loc ROM I Mai bottom,w/2-2"LPO 111 la SL MEI 20" 9 5/8" 4.5" 23/8" • I NGF - Ninilchik 2016 Moncla Rig#401 Knight Oil Tools BOP liilriirp,tlawku.1.1A. f 1 SII rrn rai itt ft in] frti 1 2.57' \ / Shaffer 71/16 5000 ifiarfi 7 114- tUitiTtlY [IC 2 3/8-3%2 variable CAMERON 44 I p N 3.68' a. H ® o I� a N Blind H 71/16 5000 H DSA 4-1/6"5M x 2-1/16" 10M Iel I11i lilt ii Choke and Kill valves are 2 1/16 10M _ l l l l l l { l I i l t l * e;zi � i "1.56' Lr ! i� ' 7 1/16 5000 ! . i In �q ' io mil,. 1 J =,i Ill lit Ill 11l III HCR 7-1/16"5M Drilling Spool w/one 4-1/16"5 M Outlets • • Ninilchik Gas Field • - SD-0.5 10/21/2016 f;tn,rp Alla a.I.I(. Greystone #1 Coil Tubing BOP n Lubricator to injection head ) 0 1.5" Tandem Stripper 1 f _I — — 4 1/16 10M It : Blind/Shear Blind/Shear j -- - // ---- - - - - I- _ [7._ Blind/Shear Blind/Shear _ It i_ = Slip a Slip ,I,'■1 _ _— € = Pipe Pipe : =1 Mud Cross I- __ ---- 4 1/16 10M X 4 1/16 10M Outlet ' 77t w/2- 2 1/16 10M full opening FMC valves 1, iso in in Olt - - l@ ID 1111KK a , 1W Manual Manual Manual Manual 2 1/16 10M 2 1/16 10M 2 1/16 10M 2 1/16 10M Crossover spool 4 1/16 10M X 7 1/16 5M • • !g3 ; 3 . a ! ,I U 2= H .] U 1 U N , Z H L. y 1] g , C U -aas 1 .fit ice k CV Q • d -2 0E4 Co 0 L c O C • o - 2 a` 0 F mi I' I Imil j ..: ' A d 'milli 4 'II■II■I i, y 1 I of o I •U A Z c I- 0 a 0 1- -- I V• O 1 Y 110 a k b a c c I° 0 d 'o fl id U O Iilli 8 O L i 0 • c00 t � � a) = v ak � 2 o & c 77 02e .$co U 2 § f « EZ E oc DE Q / �7,34.1 = © I O• •E k < L'.•- k / ) U) � m � � -0 _a « Etmk $ 77 i ■ £ 9 �.- a CO RE C ( el -0 2 2 • / � 2 � 2 ■ ■ In $ / a � a)o co Zre as § q / ti u) - > 0 c 2 0 O k c U. I0 �� U kO ® in 2E a) 2 7 « .c 0 t = § ■ 2 -6 -3 44. /a a. a) \ 2 C a) c �f ■ c -a w0 c Iz § \ Aco o C.) 0 0. km o. ■ « ■ >CCS Q. 0 0. c � � E 0 R » & & u) : - 0 § c k $ 2 � S x $ 2 it v .. ® 0 . > CD � Q > k ... U Q ■ > - c - a) 0Ci. / 2 co k 9 < a = 0 k • • Schwartz, Guy L (DOA) From: Schwartz, Guy L(DOA) Sent Monday,October 31, 2016 4:37 PM To: Taylor Wellman Subject: RE:SD 5 sundry for velocity string. (PTD 206-088) Taylor, The steps below are good . I will add this email to our wellfile. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Guy Schwartz at(907-793-1226) or(Guy.schwartz@alaska.gov). From:Taylor Wellman [mailto:twellman@hilcorp.com] Sent: Monday,October 31,2016 1:08 PM To:Schwartz,Guy L(DOA)<guy.schwartz@alaska.gov> Subject: RE:SD 5 sundry for velocity string. (PTD 206-088) Guy, You're correct on that. The original intention was to have the casing valves already made up to that new tubing head and the void test would prove integrity to that new connection. A better way to test all this is the following, which is the way we would like to proceed is listed below with changes in red. 8. Set 4" BPV. ND Tree. Set blanking plug. 9. NU 11" 5M x 7-1/16"5M tubing head,test hanger void to 5000psi. Install casing valves to the new tubing head. 10. NU 7" BOPE. Set 7"test plug.Test to 250 psi Low/2,500 psi High,annular to 250 psi Low/1,500 psi High (hold each valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Notify AOGCC 24 hrs in advance of BOP test. b. Test VBR rams on 2-3/8"test joint. 11. Bleed any pressure off tubing. Pull 7"test plug. Pull blanking plug and 4" BPV. a. If pressure will not bleed off,contact Ops Engineer for discussion prior to pumping any additional 8.5 ppg 3%KCI. If these amended steps meet your approval I can either change on the application or however you would like to proceed. Thank you, Taylor Taylor Wellman 1 • Hilcorp Alaska, LLC—Ops Engineer: Endicott& Northstar Office: (907)777-8449 Cell: (907) 947-9533 Email:twellman@hilcorp.com From: Schwartz, Guy L(DOA) [mailto:guy.schwartz@)alaska.gov] Sent: Monday, October 31, 2016 10:24 AM To:Taylor Wellman Subject: SD 5 sundry for velocity string. (PTD 206-088) Taylor, Can you elaborate how you are going to test the flange breaks on the new tubing spool (Step#9)? With 7" test plug set in the new hanger the lower flange will not see pressure or the new casing valves. Should be tested to at least 2500 psi. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Guy Schwartz at(907-793-1226) or(Guy.schwartz@alaska.gov). 2 Image Projeet Well History File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. p~Q ~Q - ~ ~~ Well History File Identifier Organizing (done) RES AN Color Items: Greyscale Items: ^ Poor Quality Originals: ^ Other: ~,wo,,~d iuuiiiiiiiiiiuu DIGITAL DATA ^ Diskettes, No. ^ Other, No/Type: ~. aes~a~~ede, iiiiuiiiuuiiuu OVERSIZED (Scannable) ^ Maps: ^ Other Items Scannable by a Large Scanner OVERSIZED (Non-Scannable) ^ Logs of various kinds: NOTES: BY: Maria Project Proofing BY: Maria ^ Other:: Date: Date: ~ ~~~-~ Scanning Preparation ~ x 30 = BY: Maria Dater ~~[.~ Production Scanning h, v~ P imuiiiimiuii n~~ D + 0~0 =TOTAL PAGES 11 g (Count does not include cover sheet) /s/ V Stage T Page Count from Scanned File: -'-`~ (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: ~ES NO BY: Maria Date: ~ ` ~ ©~{ Js/ IM Stage T If NO in stage 1, page(s) discrepancies were found: YES NO 1 ~ r BY: Maria Date: /s/ Scanning is complete at this point unless rescanning is required: II I II II II III II ((III ReScanned Ill llllllillll 11111 BY: Maria Date: /s/ Comments about this file: Quality Checked P 10/6!2005 Well History File Cover Page.doc • STATE OF ALASKA ALAI OIL AND GAS CONSERVATION COM ION REPORT OF SUNDRY WELL OPERATIONS 1 1. Operations Abandon L] Repair Well a Plug Perforations [J Perforate Li Other U Capstring Performed: Alter Casing ❑ Pull Tubing ❑ Stimulate - Frac ❑ Waiver ❑ Time Extension ❑ Change Approved Program ❑ Operat. Shutdown ❑ Stimulate - Other ❑ Re -enter Suspended Well ❑ 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Hilcorp Alaska, LLC Development El . Exploratory ❑ 206 -088 - 3. Address: 3800 Centerpoint Drive, Suite 100 Stratigraphic ❑ Service ❑ 6. API Number: Anchorage, Alaska 99503 50- 133 - 20562 -00 -00 ' 7. Property Designation (Lease Number): 8. Well Name and Number: FEE -CIRI Ninilchik Unit S Dionne 5 • 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field /Pool(s):, N/A Ninilchik Field / SD Undefined Beluga Gas " 11. Present Well Condition Summary: Total Depth measured 9,600 feet " Plugs measured 7,532 feet RECE1VP = true vertical 7,987 feet Junk measured N/A feet � � MAY 1:: Effective Depth measured 7,532 feet Packer measured 4,569 feet true vertical 5,920 feet true vertical 3,028 feet OCC `Casing Length Size MD TVD Burst Collapse Structural Conductor 91' 20" 91' 91' 3,060psi 1,500psi Surface 1,630' 9 -5/8" 1,630' 1,298' 5,750psi 3,090psi f Intermediate 4,788' 7" 4,788' 3,219' 7,240psi 5,410psi Production Liner 5,026' 4 -1/2" 9,595' 7,982' 8,930psi 7,500psi Perforation depth Measured depth See Attached Schematic SCANNED WAY 15 2013 True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth) 4 -1/2" 12.6# / L -80 4,569' 3,028' Packers and SSSV (type, measured and true vertical depth) ZXP Liner Packer N/A 4,569' 3,028' 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13 • Representative Daily Average Production or Injection Data Oil -Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure i. _ _ Prior to well operation: _ 0 3,256 18 35 215 Subsequent to operation: 0 3,255 36 35 215 1 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run N/A Exploratory Development © ' Service ❑ Stratigraphic ❑ Daily Report of Well Operations X 16. Well Status after work: Oil ❑ Gas Isl. WDSPL ❑ I GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 313 -067 Contact Chris Kanyer Email ckanverhilcorp.com Printed Name Chris Kanyer Title Reservoir Engineer e' Signature - Phone 907 - 777 -8377 Date 5/9/2013 L \\ / R BDMS M AY 14 2011 S4sl3 : Form 10 -404 Revised 10/2012 Submit Original Only 11 II Ninilchik Field SCHEMATIC Well #: Susan Dionne 05 Hilcorp Alaska. LLC Last Completed: 8/7/2006 CASING DETAIL RKEt MSL =156' 121' AGL �g Size Type Wt /Grade /Conn ID Top Btm CMTTop 4 20" Conductor 133# / K -55 / PE 18.73 Surf 91' o. r 'j 1 12 PPg/ i = + € s 9-5/8" Surface 40# / L -80 / BTC 8.835 Surf 1,630' Surface 2d 7" Intermediate 26# / L -80 / BTC 6.276 Surf 4,788' Surface e :: y,? ,; 1i ,, kt 4 -1/2" Liner 12.64 / L -80 / Hydril 563 3.958 4,569' 9,595' � P. TUBING DETAIL CI 1 4 -1/2" Tubing 12.6 # /L -80 /Buttress Mod 3.958 Surf 4,569' i r 9.5/8" t :; li CAPILLARY DETAIL t 3/8" Capillary 2205 SS Surf 5,330' '1(iZ f f 5 IN) A JEWELRY DETAIL 0 No Depth Length ID OD Item ,l 1 2,382 3.858 5.93 Baker Chemical Injection Nipple m a y 1 2 4,569' 9.55 ZXP Liner Packer w/ 15' Tieback Extension A 3 4,609' 7.97 Flex Lock Liner Hanger ' 4 6,984' 4 PAC Valve °,. i " 5 9,467' Landing Collar 6 9,509' Float Collar ' 3 ' 7 9,593' Float Shoe 3 Al PERFORATION DETAIL V K Zone Top Btm (MD) Top (TVD) Btm (TVD) FT Date Status BLG -130 5,163' 5,173' 3,567' 3,576' 10 2/21/13 Open 't BLG -130 5,251' 5,253' 3,650' 3,652' 10 2/20/13 Open �' ,.. ' ' 41 2 Va t • ; ` BLG -132 5,247' 5,257' 3,647' 3,656' 10 2/21/13 Open :a r r BLG -135 5,317' 5,343' 3,714' 3,739' 26' 6/7/07 Open C ; 3 Tyonek 5,735' 5,737' 4,123' 4,125' 2' 10/26/06 Squeezed & Casing Patched �t T -65 8,270' 8,276' 6,657' 6,663' 6' 10/24/06 Squeezed & Casing Patched t ; 7" . - - - T -83 8,508' 8,524' 6,895' 6,911' 16' 5/31/08 Squeezed T -140 9,263' 9,289' 7,650' 7,676' 26' 5/31/08 Squeezed II �+" OPEN HOLE / CEMENT DETAIL 4 4 12 -1/4" hole, Cmt w/ 404 sks (180 bbls) 12 ppg Type 1 cmt with 30 bbls, 12 ppg cmt to 9 -5/8 + 4 surface. (with partial lost returns) TXtagged@ N' , 8 -1/2" hole, Cmt w/ 254 sks (111.7 bbls) 12.5 ppg type G Lead, plus 197 sks (40.9 bbls) 15.8 7,532' Mo 7" ppg type G Tail. Bump plug, 15 bbls contaminated with 5 bbls cmt to surface, 100% returns, on8/30 /2010 ( 5 It floats held. 4 .4 4 0 - 7" hole, Cmt w/ 20 bbl 10.5 ppg spacer followed by 330 sks (118.6 bbls) 13.0 ppg 8,045' KB cmt r top from CBL run 8/7/2006. Lost circ w/83 bbls cmt displaced. PAC valve opened and 0 4 4 -1/2" immediately closed. Perfed 5,735' - 5,737' (Owen 3 -3/8" 6 spf) to cmt above 120 sks (43 bbls) �° 1 . 1, 13.0 ppg Lead followed by 50 sks (10 bbls) 15.8 ppg Tail 7.6 bbls cmt returns to surface. PI 1 .., �U TOC ,. INCLINATION DETAIL tagged@ � �� 9,341' CM ,, ,1 KOP @ 200' MD/TVD on 5/31/2007 01' - 5 r ? 6 Build 5.0 deg /100' from 200 -1434' MD 44/2" t '" � Hold 61.5 deg from 1434 -2700' MD F'BTD4,OOT TD= 9,600' Drop 2 deg /100' to 5900' MD MAX HOLE ANGLE = 61.5 1,434' Hold 1.0 deg from 5900' to TD at 9,600' MD Azimuth: 220.7 deg. Revised By: TDF 5/9/2013 • • Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SD -05 50- 133 - 20562 -00 -00 206 -088 2/16/13 4/12/13 Daily Ope ° „,;.., 2/7.6/2013 -Saturday ° M f : Pli l '111, PTW, JSA and SIMOPS. Rig up lubricator and PT to 250 psi low and 2500 psi high,RIH w/3.68" GR to 5,751' and tag patch. Got hung up for a while at bottom of perfs. RIH w/ 3 -3/8 "x9.6' dummy gun to 5,304' KB. Didn't tag - tools drop slowly until after deviation. POOH. Rig down lubricator and clean up area. 2/20/2013 - Wedn .day I aiil�tii u PTW, JSA and spot equipment. Run line thru grease tubes and put new rope socket on. Build 2- 1/2 "x2' HC, 6 spf, 60 deg phase and arm gun. Pressure test to 250 psi low and 2500 psi high. RIH with 2- 1/2 "x2' HC, 6 spf, 60 deg phase and tie into Expro Dual Radial CBL /GR /CCL log dated 25- Aug -06. Spot shot from 5,251' to 5,253' per Final Approved Perf Request Form Dated 1/22/2013 by Geologist. Tubing pressure 421 psi. Fired gun and no pressure change. POOH. All shots fired. RIH with 3 -3/8 "x10' (loaded with 3 -1/8" charges) HC, 6 spf, 60 deg phase and tie into Expro Dual Radial CBL /GR /CCL log dated 25 -Aug- 06. Spot shot from 5,247' to 5,257' per Final Approved Perf Request Form Dated 1/22/2013 by Geologist. Tubing pressure 424 psi. Attempted to fire gun and gun went to dead short. POOH. 2/21/2013 - Thursday RIH with 3 -3/8 "x10' (loaded with 3-1/8" charges) HC, 6 spf, 60 deg phase and tie into Expro Dual Radial CBL /GR /CCL log dated 25- Aug -06. Spot shot from 5,247' to 5,257' per Final Approved Perf Request Form Dated 1/22/2013 by Geologist. Tubing pressure 425 psi. Fired gun and didn't see any pressure increase. POOH. RIH with 3 -3/8 "x10' (loaded with 3 -1/8" charges) HC, 6 spf, 60 deg phase and tie into Expro Dual Radial CBL /GR /CCL log dated 25- Aug -06. Spot shot from 5,163' to 51473- per-., Final Approved Perf Request Form Dated 1/22/2013 by Geologist. Tubing pressure 427 psi. Fired gun and didn't see any pressure change. Rig down lubricator and clean up area. 4/12/2013 - Friday �x h RU Dyna Coil Unit. Stab 3/8" SS capillary line into dual barrier pack -off. Make up BHA components. Install pack -off and pressure test same against swab valve 250 psi low /3,000 psi high. RIH with 3/8" capillary string to 5,330'. Install slips, capillary string master valve, & chemical injection pump. RD Dyna Coil Unit. STATE OF ALASKA • ALA" OIL AND GAS CONSERVATION COMWION REPORT OF SUNDRY WELL OPERATIONS ... • 1. Operations Abandon U Repair Well U Plug Perforations U Perforate U Other U ! 1, .,d4,,.e C Performed: Alter Casing ❑ Pull Tubing ❑ Stimulate - Frac ❑ Waiver ❑ Time Extension ❑ Change Approved Program ❑ Operat. Shutdown ❑ Stimulate - Other ❑ Re -enter Suspended Well ❑ 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Hilcorp Alaska, LLC Development El Exploratory ❑ ' 206 -088 3. Address: 3800 Centerpoint Drive, Suite 100 Stratigraphic ❑ Service ❑ 6. API Number: Anchorage, Alaska 99503 - 50- 133 - 20562 -00 -00 7: Property Designation (Lease Number): 8. Well Name and Number: FEE -CIRI - Ninilchik Unit S Dionne 5 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field /Pool(s): N/A Ninilchik Field / SD Undefined Beluga Gas 11. Present Well Condition Summary: Total Depth measured 9,600 feet Plugs measured 7,532 feet true vertical 7,987 feet Junk measured N/A feet Effective Depth measured 7,532 feet Packer measured 4,569 feet true vertical 5,920 feet true vertical 3,028 feet Casing Length Size MD TVD Burst Collapse ! Structural Conductor 91' 20" 91' 91' 3,060psi 1,500psi Surface 1,630' 9 -5/8" 1,630' 1,298' 5,750psi 3,090psi ' Intermediate 4,788' 7" 4,788' 3,219' 7,240psi 5,410psi Production Liner 5,026' 4 -1/2" 9,595' 7,982' 8,930psi 7,500psi Perforation depth Measured depth See Attached Schematic SCANNED APR 0 3 2013 True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth) 4 -1/2" 12.6# / L -80 4,569' 3,028' Packers and SSSV (type, measured and true vertical depth) ZXP Liner Packer N/A 4,569' 3,028' 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure I Prior to well operation: 0 I 3,256 18 0 215 I Subsequent to operation: 0 3,255 36 0 215 1 114. Attachments: 15. Well Class after work: 'Copies of Logs and Surveys Run N/A Exploratory El Development - Service El Stratigraphic El Report of Well Operations X 16. Well Status after work: Oil El Service In WDSPL ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 313 -067 Contact Chris Kanyer Email ckanyeraahilcorp.com Printed Name Chris Kanyer Title Reservoir Engineer Signature N M Phone 907 - 777 -8377 Date 3/28/2013 • RaDMS MAR 2 91013 i y " /3 ")14 Form 10 -404 Revised 10/2012 Submit Original Only 4/0 • • Ninilchik Field SCHEMATIC Well #: Susan Dionne 05 Ililrora Alaska, LLC Last Completed: 8/7/2006 CASING DETAIL RFB: MSL =156' / 21' /GL �j Size Type Wt/ Grade/ Conn ID Top Btm CMT Top C ; r � , 20" Conductor 133# / K -55 / PE 18.73 Surf 91' 1 aP t " 9 -5/8" Surface 40# / L -80 / BTC 8.835 Surf 1,630' Surface S 20' 7" Intermediate 26# / L -80 / BTC 6.276 Surf 4,788' Surface 4 4 s ,' ' 1 1 k 4 -1/2" Liner 12.6# / L -80 / Hydril 563 3.958 4,569' 9,595' qq t qg d ��.yy Y yy TUBING DETAIL 3i � N ', *` 33 4 -1/2" Tubing 12.6 # /L -80 /Buttress Mod 3.958 Surf 4,569' 1 9 -5 /8" tv JEWELRY DETAIL • No Depth Length ID OD Item 4`' 1 2,382 3.858 5.93 Baker Chemical Injection Nipple 2 4,569' 9.55 ZXP Liner Packer w/ 15' Tieback Extension i 3 4,609' 7.97 Flex Lock Liner Hanger 1 1 4 6,984' 4 PAC Valve 5 9,467' Landing Collar , / 6 9,509' Float Collar ' 7 9,593' Float Collar 4 PERFORATION DETAIL 1 Zone (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status ) ,/_ BLG -130 5,163' 5,173' 3,567' 3,576' 10 3/21/13 Open ",2.1(......„ a , BLG -132 5,247' 5,257' 3,647' 3,656' 10 3/21/13 Open t, i ]' a j BLG -135 5,317' 5,343' 3,714' 3,739' 26' 6/7/07 Open Tyonek 5,735' 5,737' 4,123' 4,125' 2' 10/26/06 Squeezed & Casing Patched 1 T -65 8,270' 8,276' 6,657' 6,663' 6' 10/24/06 Squeezed & Casing Patched q T -83 8,508' 8,524' 6,895' 6,911' 16' 5/31/08 Squeezed T -140 9,263' 9,289' 7,650' 7,676' 26' 5/31/08 Squeezed PI aJ 7 d 1 1 - OPEN HOLE / CEMENT DETAIL 1 ‘.,... 12 -1/4" hole, Cmt w/ 404 sks (180 bbls) 12 ppg Type 1 cmt with 30 bbls, 12 ppg cmt to 9 -5/8" py .2 surface. (with partial lost returns) i 8 -1/2" hole, Cmt w/ 254 sks (111.7 bbls) 12.5 ppg type G Lead, plus 197 sks (40.9 bbls) 15.8 ' 7" ppg type G Tail. Bump plug, 15 bbls contaminated with 5 bbls cmt to surface, 100% returns, L 1 �+ .t4 floats held. TOC tagged @ 7,53Z MD *,, - • v ,# on8/30/2010 7" hole, Cmt w/ 20 bbl 10.5 spacer followed by 330 sks (118.6 bbls) 13.0 ppg y ppg 8,045' KB cmt F 4 1/ top from CBL run 8/7/2006. Lost circ w/83 bbls cmt displaced. PAC valve opened and immediately closed. Perfed 5,735' - 5,737' (Owen 3 -3/8" 6 spf) to cmt above 120 sks (43 bbls) 13.0 ppg Lead followed by 50 sks (10 bbls) 15.8 ppg Tail 7.6 bbls cmt returns to surface. r Y . F ' t INCLINATION DETAIL II 4 TOC tagged @9,341'CTM ' ` ' , . KOP @ 200' MD/TVD on 5/3]/2007. ' ,°` Build 5.0 deg /100' from 200 -1434' MD w /s /ti 5 Hold 61.5 deg from 1434 -2700' MD 41/2 " - -t" ' 6 7 Drop 2 deg /100' to 5900' MD Hold 1.0 deg from 5900' to TD at 9,600' MD PBTD43,007' TD =9,600 Azimuth: 220.7 deg. MAX HOLE ANGLE = 61.5 A 1,434' Revised By: TDF 3/28/2013 • • Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date SD 05 50-133-20562-00-00 206 -088 2/16/13 2/21/13 1 - r PTW, JSA and SIMOPS. Rig up lubricator and PT to 250 psi low and 2500 psi high. RIH w/3.68 GR to 5,751' and tag patch. Got hung up for a while at bottom of perfs. RIH w/ 3 -3/8 "x9.6' dummy gun to 5,304' KB. Didn't tag - tools drop slowly until after deviation. POOH. Rig down lubricator and clean up area. 2/20/2013 - Wednesday PTW, JSA and spot equipment. Run line thru grease tubes and put new rope socket on. Build 2- 1/2 "x2' HC, 6 spf, 60 deg phase and arm gun. Pressure test to 250 psi low and 2500 psi high. RIH with 2- 1/2 "x2' HC, 6 spf, 60 deg phase and tie into Expro Dual Radial CBL /GR /CCL log dated 25- Aug -06. Spot shot from 5,251' to 5,253' per Final Approved Perf Request Form Dated 1/22/2013 by Geologist. Tubing pressure 421 psi. Fired gun and no pressure change. POOH. All shots fired. RIH with 3 -3/8 "x10' (loaded with 3 -1/8" charges) HC, 6 spf, 60 deg phase and tie into Expro Dual Radial CBL /GR /CCL log dated 25 -Aug- 06. Spot shot from 5,247' to 5,257' per Final Approved Perf Request Form Dated 1/22/2013 by Geologist. Tubing pressure 424 psi. Attempted tame gun and gun went to dead short. POOH. 3/21/2013 - Thursday RIH with 3 -3/8 "x10' (loaded with 3 -1/8" charges) HC, 6 spf, 60 deg phase and tie into Expro Dual Radial CBL /GR /CCL log dated 25- Aug -06. Spot shot from 5,247' to 5,257' per Final Approved Perf Request Form Dated 1/22/2013 by Geologist. Tubing pressure 425 psi. Fired gun and didn't see any pressure increase. POOH. RIH with 3 -3/8 "x10' (loaded with 3 -1/8" charges) HC, 6 spf, 60 deg phase and tie into Expro Dual Radial CBL /GR /CCL log dated 25- Aug -06. Spot shot from 5,163' to 5,173 per Final Approved Perf Request Form Dated 1/22/2013 by Geologist. Tubing pressure 427 psi. Fired gun and didn't see any pressure change. Rig down lubricator and clean up area. • • 7 „,,„ THE STATE Alaska Oil and Gas �� ®f l 1L1 1 Conservation Commission GOVERNOR SEAN PARNELL 333 West Seventh Avenue � Anchorage, Alaska 99501 -3572 ALAS Main: 907.279.1433 Fax: 907.276.7542 SCANNED MAR 0 6 2013 Shane Bennett Operations Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 100 a0 6 -0.3 Anchorage, AK 99503 Re: Ninilchik Field, SD Undefined Beluga Gas Pool, S Dionne 5 Sundry Number: 313 -067 Dear Mr. Bennett: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, / I P? Cathy P. "oerster Chair DATED this I'” day of February, 2013. Encl. • �E RECEIVED C E ED STATE OF ALASKA FEB 0 8 2013 ALASKA OIL AND GAS CONSERVATION COMMISSION QTS Z. // 3 APPLICATION FOR SUNDRY APPROVALS AOGCC 20 AAC 25.280 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pod ❑ Repair Well ❑ Change Approved Program ❑ Suspend ❑ Plug Perforations ❑ Perforate El . Pull Tubing ❑ Time Extension ❑ Operations Shutdown ❑ Re -enter Susp. Well ❑ Stimulate ❑ Alter Casing ❑ Other. ❑ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number. Hilcorp Alaska, LLC Exploratory ❑ Development El 206-088 • 3. Address: Stratigraphic ❑ Service ❑ 6. API Number. 3800 Centerpoint Drive, Suite 100, Anchorage, AK 99503 50-133 - 20562 -00 -00 - 7. If perforating: a 56 •j 8. Well Name and Number. What Regulation or Conservation Order govems well spacing in this pool? 2 0 A{ . Will planned perforations require a spacing exception? Yes i No G Ninilchik Unit S Dionne 5 • 9. Property Designation (Lease Number): 10. Field /Pool(s): FEE -CIRI . Ninilchik Field / SD Undefined Beluga Gas • 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 9,600 • 7,987 • 7,532 5,920' 7,532 N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 91' 20" 91' 91" - 1,500 psi Surface 1,630' 9 -5/8" 1,630' 1,298' 5,750 psi 3,090 psi Intermediate 4,788' 7" 4,788' 3,219' 7,240 psi 5,410 psi Production Liner 5,026' 4 -1/2" 9,595' 7,982' 8,930 psi 7,500 psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Schematic See Schematic 4 -1/2" 12.6# / L -80 4,569' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): ZXP Liner Packer / SSSV - N/A Packer 4,569' (MD) 3,028' (TVD) / SSSV - N/A 12. Attachments: Description Summary of Proposal El 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development El Service ❑ 14. Estimated Date for 15. Well Status after proposed work: 2/12/2013 Commencing Operations: Oil ❑ Gas GI WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Chris Myers Email cmversB ihilcorp.com Printed Name ane Bennett Title Operations Engineer Signatur Phone 907 777 -8425 Date 2/8/2013 ` COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: `e.-- ©co-7 Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: R BDAAS FEB 15 20 * 1.-. Spacing Exception Required? Yes ❑ No i Subsequent Form Required: /0- ` v 1 / APPROVED BY / Approved by: COMMISSIONER THE COMMISSION Date: 4 23 RI N Subm Formand on3 eve 1 1 Approved application is valid for 12 months from the date of app r oval. Attachments in Duplicate • • Well Prognosis Well: SD -5 Hilcorp Alaska, LL Date: 2/7/2013 Well Name: Ninilchik Unit S Dionne 5 API Number: 50- 133 - 20562 -00 -00 Current Status: Flowing gas completion Leg: N/A Estimated Start Date: February 12, 2013 Rig: N/A Reg. Approval Req'd? 10 -403 Date Reg. Approval Rec'vd: Regulatory Contact: Tom Fouts 777 -8398 Permit to Drill Number: 206 -088 First Call Engineer: Shane Bennett (907) 777 -8425 (0) (325) 203 -7487 (M) Second Call Engineer: Chris Myers (907) 777 -8333 (0) (907) 398 -9955 (M) AFE Number: Current Bottom Hole Pressure: —625 psi Maximum Expected BHP: —1,581 psi @ 3,651' TVD Calculated using .433psi /ft gradient Max. Allowable Surface Pressure: —1,446 psi (Based on 0.037 psi /ft gas gradient) Brief Well Summary This well was drilled and completed as a gas well in 2006. The well began to producing water in early 2012 and is currently lifting "30bwpd with the help of soap sticks. The proposed completion plan is to add additional perforations in the Beluga 130 to help to sustain the well above the unloading rate. Contingency operations include installing a 3/8" capstring to the existing Beluga 135 perfs to assist in unloading water from well. NOTE: As discussed in the attached email, the original Well Completion Report (form 10 -407) was incorrect, listing the pool as Undefined Tyonek. The original produced interval is the Beluga 135 sand and the pool should be labeled as Undefined Beluga. Summary Procedure 1. RU E -line and test lubricator to 250psi low /2,500psi. 2. Perforate the Beluga 130 sands at +1- 5,163' to +/- 5,173' and +/- 5,247' to +/- 5,257'. 3. RD Eline. 4. Turn well over to production & flow test well. VONTINGENCY (If well does not sustain rate above liquid loading rate) 5. RU Dyna Coil Unit. 6. Stab 3/8" SS capillary line into dual barrier pack -off. Make up BHA components. Install pack -off and pressure test same against swab valve 250 psi low /3,000 psi high. 7. RIH with 3/8" capillary string to +1- 5,330'. 8. Install slips, capillary string master valve, & chemical injection pump. 9. RD Dyna Coil Unit. 10. Turn well over to production. Attachments: 1. As -built Well Schematic 2. Proposed Well Schematic 3. Email Correspondence with AOGCC Guy Schwartz • • 14 Ninilchik Field SCHEMATIC Well #:Susan Dionne 05 Hilcorp Alaska, LLC Last Comoleted:8 /7/2006 CASING DETAIL RFBMSL= 156'/21' Size Type Wt/ Grade/ Conn ID Top Btm CMT Top J ' V 20" Conductor 133# / K -55 / PE 18.73 Surf 91' 9 -5/8" Surface 40# / L -80 /BTC 8.835 Surf 1,630' Surfa ce 7" Intermediate 26# / L-80 / BTC 6.276 Surf 4,788' Surface v 4 -1/2" Liner 12.6# / L -80 / Hydril 563 3.958 4,569' 9,595' P ' } TUBING DETAIL 4 4 -1/2" Tubing 12.6 # /L -80 /Buttress Mod 3.958 Surf 4,569' 4 A JEWELRY DETAIL ,, No Depth Length ID OD Item 5 4 1 2,382 3.858 5.93 Baker Chemical Injection Nipple 9 ' 2 4,569' 9.55 ZXP Liner Packer w/ 15' Tieback Extension * 3 4,609' 7.97 Flex Lock Liner Hanger 1 s 4 6,984' 4 PAC Valve ; ') 5 9,467' Landing Collar , .1 6 9,509' Float Collar It j 7 9,593' Float Collar PERFORATION DETAIL } 1 e Zone Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Date Status BLG -135 5,317' 5,343' 3,714' 3,739' 26' 6/7/07 Open x ; 1 Tyonek 5,735' 5,737' 4,123' 4,125' 2' 10/26/06 Squeezed & Casing Patched a *' T -65 8,270' 8,276' 6,657' 6,663' 6' 10/24/06 Squeezed & Casing Patched i 4 T -83 8,508' 8,524' 6,895' 6,911' 16' 5/31/08 Squeezed — :' 2 T -140 9,263' 9,289' 7,650' 7,676' 26' 5/31/08 Squeezed 1t, _ OPEN HOLE / CEMENT DETAIL i ii . i a 12 -1 4 hole, Cmt w/ 404 sks (180 bbls) 12 Type 1 cmt with 30 bbls, 12 3 9 -5/8, " / / ( ) ppg Yp ppg cmt to l � MI surface. (with partial lost returns) ' I II 8-1/2" hole, Cmt w/ 254 sks (111.7 bbls) 12.5 ppg type G Lead, plus 197 sks (40.9 bbls) 15.8 7 „ 1 - r 7 �,, ppg type G Tail. Bump plug, 15 bbls contaminated with 5 bbls cmt to surface, 100% returns, '� sX floats held. r 7" hole, Cmt w/ 20 bbl 10.5 ppg spacer followed by 330 sks (118.6 bbls) 13.0 ppg 8,045' KB cmt top from CBL run 8/7/2006. Lost circ w/83 bbls cmt displaced. PAC valve opened and + »� • � 4 4 1/2.. immediately closed. Perfed 5,735' - 5,737' (Owen 3 -3/8" 6 spf) to cmt above 120 sks (43 bbls) T°ctaapd@7,53PN +.. :1,0 �'? 13M ppg Lead followed by 50 sks (10 bbls) 15.8 ppg Tail 7.6 bbls cmt returns to surface. an 8/30/2010 I .. l t INCLINATION DETAIL ..1'11 1 z, KOP @ 200' MD/TVD l ,; Build 5.0 deg/100' from 200 -1434' MD o - "- Hold 61.5 deg from 1434 -2700' MD '•1 Drop 2 deg/100' to 5900' MD Toa d @9,341 , r ° ' j u . an 5/31/2007 47. Hold 1.0 deg from 5900' to TD at 9,600' MD 3 + « L Azimuth: 220.7 deg. 4-1/2" 4 "" { _ , 6 7 PBTD 43,007' TD = 9,600' MAX HOLE ANGLE = 61.5 ao 1,434' Revised By: JLL 02 -08 -2013 • • Ninilchik Field PROPOSED Well #:Susan Dionne 05 Hilcorp Alaska, LLC Last Comnleted:8 /7/2006 CASING DETAIL RFC: MS_ =156' 121' AGL g�7 Size Type Wt/ Grade/ Conn ID Top Btm CMT Top 1, !P 1. ) + 20" Conductor 133# / K -55 / PE 18.73 Surf 91' 9 -5/8" Surface 40# / L -80 / BTC 8.835 Surf 1,630' 12ppg/ Surface 2d' v 1 �+ 7" Intermediate 26 # /L -80 /BTC 6.276 Surf 4,788' Surface * N .'M i j+* i 4 - 1/2" Liner 12.6 # / L -80 / Hydril 563 3,958 4,569' 9,595' a 77 �1 TUBING DETAIL y 1 4 -1/2" Tubing 12.6 # /L -80 /Buttress Mod 3.958 Surf 4,569' 9-5/g,1 4 r « JEWELRY DETAIL a ; No Depth Length ID OD Item 0 1 2,382 3.858 5.93 Baker Chemical Injection Nipple rti 2 4,569' 9.55 ZXP Liner Packer w/ 15' Tieback Extension r. >* 3 4,609' 7.97 Flex Lock Liner Hanger `j 1 4 4 6,984' 4 PAC Valve '4 5 9,467' Landing Collar 6 9,509' Float Collar 7 9,593' Float Collar ir . PERFORATION DETAIL it ii Zone Top Btm (MD) Top (TVD) Btm (TVD) FT Date Status (MD) BLG -130a ±5,163' ±5,173' ±3,567' ±3,576' 10 Future r BLG -130b ±5,247' ±5,257' ±3,647' ±3,656' 10 Future k r BLG -135 5,317' 5,343' 3,714' 3,739' 26' 6/7/07 Open t A , Tyonek 5,735' 5,737' 4,123' 4,125' 2' 10/26/06 Squeezed & Casing Patched ' - 2 T -65 8,270' 8,276' 6,657' 6,663' 6' 10/24/06 Squeezed & Casing Patched z T -83 8,508' 8,524' 6,895' 6,911' 16' 5/31/08 Squeezed _a . ) 7: c 3 T -140 9,263' 9,289' 7,650' 7,676' 26' 5/31/08 Squeezed IU 11 4 1 I' " OPEN HOLE / CEMENT DETAIL 9 -5/8" 12 -1/4" hole, Cmt w/ 404 sks (180 bbls) 12 ppg Type 1 cmt with 30 bbls, 12 ppg cmt to -s 7 - surface. (with partial lost returns) ,v 8 -1/2" hole, Cmt w/ 254 sks (111.7 bbls) 12.5 ppg type G Lead, plus 197 sks (40.9 bbls) 15.8 . *± 7" ppg type G Tail. Bump plug, 15 bbls contaminated with 5 bbls cmt to surface, 100% returns, R _ -=----= - 4 floats held. TOCtagged @ 7,532 MD 0n8/30/2010 7" hole, Cmt w/ 20 bbl 10.5 ppg spacer followed by 330 sks (118.6 bbls) 13.0 ppg 8,045' KB cmt i top from CBL run 8/7/2006. Lost circ w/83 bbls cmt displaced. PAC valve opened and 4 1/2" immediately closed. Perfed 5,735' - 5,737' (Owen 3 -3/8" 6 spf) to cmt above 120 sks (43 bbls) 13.0 ppg Lead followed by 50 sks (10 bbls) 15.8 ppg Tail 7.6 bbls cmt returns to surface. INCLINATION DETAIL • TOC tagged @ 9,34r CPA KOP @ 200' MD/TVD on 5/31I2007 Build 5.0 deg/100' from 200 -1434' MD 5 Hold 61.5 deg from 1434 -2700' MD 4112 s 7 Drop 2 deg/100' to 5900' MD Hold 1.0 deg from 5900' to TD at 9,600' MD PBTD 8,00T TD = 9,600' Azimuth: 220.7 deg. MAX HOLE ANGLE = 61.5 A 1,434' Revised By: JLL 02/08/2013 • • Davies, Stephen F (DOA) From: David Buthman [dbuthman @hilcorp.com] Sent: Tuesday, February 12, 2013 5:00 PM To: Davies, Stephen F (DOA) Cc: Chris Kanyer Subject: FW: Applications for Sundry Approvals: Susan Dionne 5 and 6 Hi Steve, Regarding the Dionne 5 and 6 wells: 1. See the cross section, below. The spacing between the Dionne 5 and the Paxton 4 at the pertinent level is 1485'; however, the recommended perforations in the Dionne 5 are not capable of production in the Paxton 4 (the pink perf's are open productive perfs, the black ones are ones with potential). 2. Conservation Order 6 -07 exempts the Dionne 6 from spacing in the Beluga. I can provide additional clarifications, if necessary; just let me know. Regards, David B. Buthman Senior Geologist Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 dbuthmanPhilcorp.com office: 907 - 777 -8375 mobile: 907 - 854 -4543 1 • • 0 . . _ . 11 PAXTON 4 DIONNE 5 • . . . . .. . . .. 2 134.33 :' '8,136.25' . . . . —,---.. 4 WNW . • .. Mill . , . _ _I i L t .14 r.. exited rf _ ..._ ,.......... .. . . or f vat ems - - - • • -1 -_'............ - -" .. _ . . , IL il, ' -.,---,......--... - ) •. . - , . . — - - N)' . ' . .4.4....-- --.; ....e, -*-.104/0•_ . ' . .. -..,•■•• .' ' ' ' . ' . ' ' . 'L..-.- -21.::: 3 '' ' r - , . . . . . .7: - _ i 1 . 1.1 1 ' . ■ p . . k.. ..... _,...„.......... . . Rec per% r . IIIIL • .A.. • . _ _ ., . ... _ .- --- 4F--- rt ositva _ ....„7- • R . -,..-....._. s . ..,. - - - , .. • ;* . Plimirpkunt r°11 rle -fil* 4 •: . - '' Doule..5 ard Piano a an INV i owt gibe leg OM lisles-135 , _ . - , • , . 2 • Juanita Lovett From: Tom Fouts Sent: Wednesday, January 09, 2013 10:01 AM To: Chris Kanyer; David Buthman Subject: FW: Susanne Dionne #5 - PTD# 206 -088 From: Schwartz, Guy L (DOA) [ mailto:guy.schwartzOalaska.gov] Sent: Wednesday, January 09, 2013 9:52 AM To: Tom Fouts - (C) Subject: RE: Susanne Dionne #5 - PTD# 206 -088 Tom, It would be best to submit a 10 -403 requesting the perforations. As part of the application explain the issue with the Tyonek pool mistake on the original 10-407 page. Guy Schwartz Senior Petroleum Engineer AOGCC 793 -1226 (office) 444 -3433 (cell) From: Tom Fouts - (C) [mailto:tfouts hilcorp.com] Sent: Wednesday, January 09, 2013 9:33 AM To: Schwartz, Guy L (DOA) Cc: Chris Kanyer; David Buthman Subject: Susanne Dionne #5 - PTD# 206 -088 Guy, We are looking at adding perforations to the Beluga -135 zone above the existing perfs for Susan Dionne #5. On the 10- 407 (See Attached) box # 15 states the field as Ninilchik and the pool as Tyonek. The pool listing is incorrect and should be listed as Beluga. How should I proceed forward with my sundry submittal for this well? My intent was to file a 10 -404 but due to this discrepancy I would like some clarification. Thanks, Tom Fouts ( Construction Manager Hilcorp Alaska, LLC tfoutsPhilcorp.com Direct: (907) 777 -8398 Mobile: (907) 351 -5749 ti . : .. t 1 5 De aa'a Q rt ne„ ,.., y ...,," - : , : ...,. Y ,..., :, \,,,,,‘' , : „n.. 4� �tofet r�rtert• 3 r ..,... ,_... .a..,. �, 6 P e't toe tB7' : : : : Y • *pert stele lop of tie 3 . *ert as e l once errr • m ar es tt .. r, •i t. 4 ° * xP O 1 : , : ; - ith ffi til t. - : + - > EUt 5 o r 4 1 rt • o- ;, >b,= =..,. `. ,f., n_. ate t those et P< ��• , # wet et . - !"A CTON 5 From: Chris Kanyer Sent: Monday, February 11, 2013 2:53 PM To: David Buthman Subject: FW: Applications for Sundry Approvals: Susan Dionne 5 and 6 FYI. Chris Kanyer I Reservoir Engineer II NM. A uako, I,t :; ckanyer @hilcorp.com Direct: (907) 777 -8377 Mobile: (907) 250 -0374 From: Chris Myers Sent: Monday, February 11, 2013 2:07 PM To: Chris Kanyer Subject: FW: Applications for Sundry Approvals: Susan Dionne 5 and 6 Chris, Can you answer Steve's question? 3 • • Chris Myers Operations Manager SKE Mayor!, . 1'aska Li ' Work 907 - 777 -8333 Cell 907 - 398 -9955 Fax 907- 777 -8510 From: Davies, Stephen F (DOA) [ mailto :steve.davies(Talaska.gov] Sent: Monday, February 11, 2013 8:25 AM To: Chris Myers Cc: Schwartz, Guy L (DOA) Subject: Applications for Sundry Approvals: Susan Dionne 5 and 6 Chris, I am the AOGCC geologist with responsibility for the Ninilchik Field. I'm reviewing the Applications for Sundry Approvals for the Susan Dionne 5 and 6 wells. These sundry applications request approval to perforate Beluga sands. Can you please provide the distances from these proposed Beluga perforations to the nearest perforations open to other Beluga sands in surrounding wells? Thanks, Steve Davies AOGCC 907 - 793 -1224 4 ~~ ~:> ~,~` ~ ~ ~ . ~~ ~.x~ z ;~, 4. _ s~ ~' ` ~% MICROFILMED 6/30/201.0 DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE C:\temp\Temporary Internet Ftes\OLK91Microfilm_Marker.doc 3 Mo-,~ DATA SUBMITTAL COMPLIANCE REPORT 9/17/2008 Permit to Drill 2060880 Well Name/No. NINILCHIK UNIT S DIONNE 5 Operator MARATHON OIL CO API No. 50-133-20562-00-00 MD 9600 TVD 7987 Completion Date 10/3/2006 Completion Status 1-GAS Current Status 1-GAS UIC N REQUIRED INFORMATION Mud Log No Samples No Directional Survey DATA INFORMATION Types Electric or Other Logs Run: Quad Combo, CBL, GR (data taken from Logs Portion of Master Well Data Maint Well Log Information: Log/ Electr Data Digital Dataset Log Log Run Interval OH / Type Med/Frmt Number Name Scale Media No Stant Stop CH Received Comments ~D C Las 14290 Induction/Resistivity 4750 9583 Open 12/14/2006 LAS Mudlog, Morning ', Reports w/Graphics Well Cores/Samples Information: Name ADDITIONAL INFORMATION Well Cored? `(~ Chips Received? Y1'iV'~ Analysis Y~ Received? Comments: Sample Interval Set Start Stop Sent Received Number Comments Daily History Received? Formation Tops ~ N Compliance Reviewed By: ~~ _ Date: __.__ p • ~ Page 1 of 1 Maunder, Thomas E (DOA) From: Skiba, Kevin J. [kskiba@marathonoit.comj Sent: Tuesday, December 11, 2007 12:01 PM To: Maunder, Thomas E (DOA) Cc: Skiba, Kevin J. Subject: RE: SD #5 (206-088) Attachments: SD-5 Operation Summary for June 2007.x1s Tom, ~. As per our discussion, the correct completion date for SD-5 well is October~2006._ This is the day that the first holes were perforated through the casing. This well was a water producer. The 1st set of perforations and those that followed, in 2006, did not produce any gas. Continued efforts were made in 2007 with perforation additions on June 6th. June 6, 2007 was the first day that the well actually produced gas and came on production. Attached is the operation summary for the work that was completed in June of 2007. Due to technical difficulties, the format of the operation summary is different than we normally send you. Let me know if you need anything else, Kevin Skiba Production Technician Marathon Oil Company Office (907} 2$3-1371 Cell (90?} 394-1332 Fax (907) 2$3-1350 From: Maunder, Thomas E (DOA} [mailto:tom.maunder@aiaska.govj Sent: Tuesday, December 11, 2007 9:23 AM To: Skiba, Kevin J. Cc: Arthur C Saltmarsh Subject: SD #S (206-088} Kevin, You did send the 3 missing pages from the operations report, thanks. Those operations end June 2, 2007. On the 407 sheet, the completion date is shown as July 10, 2007. Was there further work done? t know this one is confusing with all the work done on the well and the fact that the well would not produce. However, it does appear that the well was physically completed in October 2006. Based on the operations report, I would use October 31 as the completion date since that appears to be the first °break" in activvities. At that point, the wet! would be a St gas well. Talk with your colleagues and get back to me. Tom Maunder, PE AOGCC 12/12/2007 Page 1 of 1 Maunder, Thomas E (DOA) From: Skiba, Kevin J. [kskiba@MarathonOil.Com] Sent: Monday, December 10, 2007 4:22 PM To: Maunder, Thomas E (DOA) Subject: RE: Susan Dionne #5 (206-088) Attachments: SD-5 Op Summary 3 page.pdf Tom, Here are the three missing Operation Summary pages for SD-5. Sorry for the inconvenience, Kevin Skiba Production Technician Marathon Oil Company Office (907) 283-1371 Cell (907} 394-1332 Fax (907) 283-1350 ~~~~ ~~ ~PP~~~~~~ ~ ~~ 0`1 From: Maunder, Thomas E (DOA} [mailto:tom.maunder@alaska.gov] Seat: Friday, December 07, 2007 4:25 PM Ta: Skiba, Kevin J. Subject: Susan Dionne #5 (206-088) Kevin, 1 am reviewing the 407 recently submitted for the well. It appears that 3 pages of the final work summary are missing. The operations summary ends on page 5 of 8 at 16:20, 11/8/06. Would you please send the missing pages? Email is fine. Thanks in advance. Tom Maunder, PE AOGCC 1211 OJ2007 Alaska Business Unit Marathon P.Q. Box 1949 MARATHON o-11 t;ampany Kenai, AK 99611-1949 Telephone 907/283-1311 Fax 907!283-6175 November 28, 2007 Tom Maunder AOGCG 333 West 7~' Ave ~~ Suite 100 ~~~ ~ ~ ~pp'C Anchorage, AK 99501 t~laska Oil & Oas ~o~s. ~;o~~:missior Reference: 10-407 Sundry Submission Anchorage Field: Ninilchik Unit Well: Susan Dionne #5 Permit: PTD #206-088 and 10-403 #307-196 Dear Mr. Maunder: Attached and submitted for your records is the Form 10-407 to complete the Susan Dionne #5 well. An operational summary, directional survey, and well schematic are also included. Per the conditions of approval for 10-403 #307-196 to plug back and add perforations in this well during the completion phase, this 10-407 will also serve to cover the subsequent reporting for that work. If you would like any other information, please contact me at 394-3060 or kdwalsh aC?.marathonoil.com. Sincerely, I~~.~~ Ken D. Walsh Senior Production Engineer Enclosures: 10-407 Sundry Well Schematic Operations Procedure Directional Survey cc: AOGCC Houston Well File Kenai Well File K. Walsh K. Skiba o~ ~~~~f`ti'~D STATE OF ALASKA NOV ~ S 207 ALASKA OlL AND GAS CONSERVATION COMMISSION WELL COMPLETION QR RECOMPLETION REP~,,~Lmmisslon 1a. Well Status: Ol^ GasO Plugged ^ Abandoned ^ Suspended ^ 20AAC25.1o5 20AAC25a1o GINJ^ WINJ^ WDSPL^ WAG^ Other^ No. of Completions: 1b. Well Class: Development ^ Explorafory^ Service ~ StratigraphicTest^ 2.Operator Name: Marathon Oil Company 5. Date Comp., Susp., or Abandyp ~ 12 Permit to Drill. Number: 206-088 _ Whir ' (o 3. Address: P.O. Box 1'.949 Kenai, AK 99611- 1949 6. Date Spudded: 7l13I2o06 13. API Number: 50.133-20562-00-00 " 4a. Location of Well (Governmental Section): Surface: 150' FSL,1,25T FEL, Sec. 6, T1 S, R13W, S.M ~ 7. date TD Reached: 7/31!2006 14. Well Name and Number: Susan Dionne 5 ' G~ Top of Productiv ~ 3~~ ?~~f' ,9~'t'~~L,3;+4f4LFEL, Sec. 7, T1S, R13W, SM.~ 8. KB {ft above MSL): 156` ~ Ground (ft MSL): 135' 15. Field/Pool{s): Ninilchik Unit - Total Depth: a,y~p ~jC~~ 4;Sf+2' fNL, ST64G' FEL, Sec.. 7, T1 S, R43W, S.M. 9. Plug Back Depth(MD+TVD): 800T + 6395' Tyonek Pool 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 213,176:67 y- 2,236,681.97 Zone- 4 10. Totai Depth(MD + TVD): 9,600' MD -7,987 TVb 16. Property Designation: CIRI C - 061505 TPI: x- 220,725.00 Y- 2,224,268.00 Zone- 4 Total Depth: x- 220,725x00 y- .2,224,268.00 Zone- 4 11. SSSV Depth {MD + TVD): NIA 17. Land Use Permit: 18, birectionai Survey: Yes s No (Submit electronic and printed information per 20 AAO 25.050) 19. Water Depth.., if Offshore: N/A {ft MSL) 2Q. Thickness of Permafrost (TVD): N/A 21. logs Obtained {List all logs here and, submit electronic and printed information per 20 AAC 25.071); Quad Combo, GBL, GR 22. CASING, LINER AND CEMENTING RECORD CA I G WT. PER GRADE SETTING DEPTH MD SETTING DEPTH TVD' HOLE SIZE CEMENTING RECORD AMOUNT S N ~ TOP BOTTOM TOP BOTTOM PULLED 20" 133 ppfi K-55 0' 91' 0' 91' Driven NA 9-518" 40 ppfi L-80 0' 1,630' 0' 1.,29$' 12-1/2" 404 sacks, 12ppg, Type 1 NA 7" 26 ppf L-80 0' 4,7$8' 0' 3,218' 8-1/2" z54 sacks, 12.5ppg, class G - NA 197 sacks, 15.Bppg, class G 4-1l2" 12.6 ppfi L-$0 4,569' 9,595' 3,028' 7,982' 7" 330 sacks, 13ppg, class G NA 23.Open to production or injection? Yes 0 Na^ If Yes,list each 24. TUBING RECORD interval open (MD+TVD of Top & Bottom; Perforation Size and Number): SIZE DEPTH SET (MD) PACKER SET (MD) 531 T-5343' MD + 3714'-3739' TVD 0.42" EH at 6 SPF 4112" 4,569' 4,569' 25. ACID, FRA CTURE, CEMENT S4tJEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT AND. KIND OF MATERIAL USED 5,735' - 5,73T 120 sacks, 13ppg, glass G 50 sacks, 15.8pgg, class G 8007 - 9325` 103 sacks, 15.8 ppg, class G 26. PRODUCTION TEST Dale First Production: 7114/2007 Method of Operation (Flowing, gas lift, etc): Flowing bate of Test: 7/10/2007 Hours Tesfed: 24 Production for Test Period Oil-6bl> 0 Gas-MCFc 9502 Water-Bbl: 0 Choke Size: Gas-(7il Ratio: Fiow Tubing Press, 1350 Casing Press: 0 Calculated. 24-Hour Rate ~- Oil-Bbl: 0 Gas-MCF: 9502 Water-Bbl: 0 Oil Gravity -API (corr): N/A 27. GORE DATA Conventional Core(s) Acquired? Yes ^ No ^~ Sdewail Cores Acquired? Yes. ^ No Q if Yes to either question; list formations and intervals cored (MD+TVb of top and bottom of`eaeh), and summarize lithology and presence of oil:, gas or water (submit separate sheets with this form, if needed). Submit detailed descriptions, core chips, photographs and laboratory analytical results per 2D AAC 25.071. Ct3fv9PLETlON~ J~ ~~pp ~, ~~ ~~lto Form 10-407 Revised 2!2007 CONTINUED ON REVERSE.. /'_ ~ ~ 28. GEOLOGIC MARKERS (List all formations and markers enc:ountered}: 29. FORMATION TESTS NAME MD TVD Weli tested? ~ Yes No if yes, list intervals and formations tested, briefly summarizing test results. Attach separate sheets to this form, if Beluga 1239 1100 needed, and submit detailed test information per 20 AAC 25.071. Tyonek 5293 3890 9263' MD Pert: 9263-9289'MD (10!3!2008) 8508' MD Pert: 8508-8524'MD (10/3J2008) 8270' MD Pert: 8270-8278'MD (10!3/2006) (10!4!2008) PT log indicated small amount of gas from 8508-8524'MO and water from 8270-8278'MD. Formation at total depth: 30. List of Attachments: 31. I hereby certify that the foregoing. is true and correct to the best of my knowledge. Contact: Kevin Skiba (907) 283-1371 sh Title: Senior Production Engineer Printed Name: Ken D. W al ~ l / ~ ~ 7 D 28/20 ~~ ~ v ate: 11! 0 Phone: (907) 283-1371 Signature: t,JCJ I,. • INSTRUCTIONS General: This form is designed for submitting a complete and coned well completion report and log on ail types of lands and leases in Alaska. Submit a well schematic diagram with each 10-407 well cempletion report and 10-404 well sundry report when the downhole well design is changed. Item 1a: Classification of Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI (Top of Producing Interval). Item 8: The Kelly Bushing and Ground Level elevations in feet above mean sea level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 20: Report true vertical thickness of permafrost in Box 20. Provide MD and TVD for the top and base of permafrost in Box 28. Item 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the Wocation of the cementing tool. Item 23: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 27: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Submit detaited description and analytical laboratory information required by 20 AAC 25.071. Item 29; Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Form 10-407 Revised 2/2007 r: Saltmarsh, Arthur C (DOA) Page 1 of 1 From: Skiba, Kevin J. [kskiba@marathonoil.com} Sent: Wednesday, January 02, 2008 6:14 PM To: Saltmarsh, Arthur C (DOA) Subject: SD-5 Correct Down Hole Locations.xls Art, Here is the Let me kno Kevin Skiba Production Technician Marathon Oii Company Office (907) 283-1371 Cell (907) 394-1332 Fax (907) 283-1350 Susan Dionne 5 4a. Location o Surface: 150' FSL, 1,257' FEL, Sec. 6, T1S, R13W, S.M. Top of Produc 2,296' FNL, 3,460' FEL, Sec. 7, T1S, R13W, S.M. Total Depth: 2,400' FNL, 3,596' FEL, Sec. 7, T1S, R13W, S.M. Location o (NAD27) rface: x- 213,176.67 y- 2,236,631.97 Zone- 4 I: x- 210,932.00 y- 2,234,143.00 Zone- 4 al Depth: x- 210,792.00 y- 2,234,044.00 Zone- 4 1 /9/2008 Susan Dionne #5 Ninilchik Unit 150' FSL 8 1257' FEL MARATNpM Sec. 6-T1S-R13W S.M. Post- 2007 Work Updated BM2I2007 by KDW Conductor 20" K55 133 Ppf TOE, Bottom MD 0' 91' TVD 0' 91' KOP ®200' MDITVD Build 5.0 dog/100" from 200-1434' MD Nold 61.5 deg from 1434-2700' MD Drop T deg1100' to 5900' MD Hold 1.0 deg from 5900' to TD at 9,600' MD Azimuth: 220.7 deg. Baker Chemical Injection Nipple Q 2385' MD (Top) 5.930' 00/3.858" ID 8430 psi bursV7500 psi collapse ZXP Liner Packer with 15' Tieback Extension @ 4,569' MD (Top) Flex-Lock Liner Hanger @ 4607' MD (Top) PAC valve @ 6984' KB (4' long) Landing Collar @ 9,467' MD (Top) Float Collar @ 9,509' MD (Top) Float Shce @ 9595' MD (Bottom) Surface Casino 9-518" 40 ppf L-80 BTC I4.L Bottom MD 0' 1030' TVD 0' 1298 12-t14" hole with 404 sks (180 bbis)12 ppg Type 1 cement with 30 bbls 12 ppg cement to surface. with partial lost returns. Intermediate Carina 7" 26 ppf L-80 Zqp- om MD 0' 4788' TVD 0' 3218' 8-112" hole with 254 sks (111.7 bbls)12.5 ppg Lead + 197 sks (40.9 bbls)15.8 ppg Tail Bumped plug, l5 bbl contaminate + 5 bbls cement to surface, 100% returns, floats held BTC PE inex rerts: dD TVD Net Ft b-573~ 4123125' 2' Owen Squeeze Perfs (3.318" fi SPF8(/121106) ched with Owen 11.75' x 3.80 OD x 3.375" ID (5733'5744.75') on 10!2612008. 73343' 3714-3739' 26' Owon 3-318" 8 SPF O6/0fi12007 :d Cement Top ins(de liner at 8007' MD (6395' on 611/2007 with 2"gauge ring. nt placed with CT from 8090'-9325' MD. -~m.~,.~.- .:.. Cement Top at 8045' KB 1st Stage Cement Top at KB 2nd Stage Exoro Radial Bond Loa Formation Tops: Formation Deoth(MDf DeothlTVDI Beluga 920 872 Tyonek 5000 3418 TD 8600 7987 F2-8878' 6660-6667' 6' Owen 3-318" 6 SPF 10128.312006 Wet- Patched with Owen 75' x 3.80 OD x 3.375" ID (8268'-8279.75') on tOf2412006 F3-8g2F 6899-6915' 16' Owen 3-316" 6 SPF 1 010 2/20 0 6 i4.82g0' 7851-7677' 26' Owen 3-318" 6 SPF 1 010 212 0 0 6 Liner 4-112" 12.6 ppf L-80 Hydril 563 Tog Bottom M D 4569' 9595' TVD 3028' 7982' 7" hole with 20 bbl 10.5 ppg spacer followed by 330 sks (118.6 bbls)13.0 ppg 8045' KB cement top from CBL Run 817/2006. Lost circ w183 obis cmt displaced. PAC valve opened and immediately closed. Perfed 5735-5737' (Owen 3318" 6 spQ to cement above 120 sks (43 bbl) 13.0 ppg lead followed by 50 sks (10 bbls) 15.8 ppg tail 7.6 bbls cement returns to surface. TD: 9600' MD 17987' TVD Marafihon Oil Company Page 1 of s Operations Sulmr~ary Report Legal Well Name: SUSAN DIQNNE 5 Common Well Name: SUSAN DI~NNE 5 Spud Date: 7/13/2006 Event Name: ORIGINAL DRILLING Start: 7/11/2006 End: 8/x/2006 Contractor Name: GLACIER. DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date I From. - To ~ Hours I Code I Co e L Phase ( Description of Operations 7/11:/2006 ~ 06:00 - 1$:00 ~ 12.00 ~ RURD_~ RIG_ ~ MIRU 18.00 - 00:00 ( 6.00 RURD_I RIG_ I MIRU 00:00 - 06:00 6.00 RURD_ RIG_ MIRU ~ 7/12/2006 ~ 06:00 - 1:8:00 , 12.00 ~ RURD_~ RIG_ ~ MIRU 18:00-.06:00 ~ 12.00 RURD_~RIG_ MIRU 7/13/2006 ~ 06;00 - 18:00 ( 12.00 ~ RURD_~ RIG_ ~ MIRU 18:00 - 23:00 5.00 NUND BODE SURDRL 23:00 - 01:00 2:00 REPAIR RIG_ SURDRL 01:00 - 02:00. 1.00 TEST BOPE SURDRL 02.00 - 03:00 ~ 1.OOI PULD_ DP_ SURDRL 03:00 - 06:00 3.00 PULp_ DP_ SURDRL 06.00 - p7;30 1.50 PULD_ BHA_ SURDRL 07:30-14:00 6.50 DRILL_ ROT_ SURDRL PJSM ;Load Out Rig And Mave To 5D5. Set And R/U Camp Units. Set Sub, Mud Boat, Pits, Generator, Boiler And Water Tank. Set Trip Tank. Spot Shop And Parts House. R/U Hand rails. Run Service Lines. PJSM ;Run Electrical Lines, Level Carrier On Mud Boat. Set Cuttings & Hanson Tank. Set Stairways. PJSM ;Set Dog ~ Choke Houses. R/U Wind Wails. Set Out Riggers On Dog House Side: Continue Running Electrical And Service Lines . R/U Pits. Set Rear Stairways And Flow Lines.. No HIE Issues. PJSM Raise Masf To Floor. Set Back Landing And. Stairs:. Set Back Windwalls.Rig Up Drillers Console-Hydraulic Control Lines,Fill Mud Pits With Fresh Water.Prep Derrick To Scope,Scope Derrick.Spot #3 Mud Pump. PJSM; R/U Torque Tube,Build Mud Volume.Spot MI Sotids Van.Pick-up Tap Drive.Nipple Up Diverter. Complete. Mixing Spud Mud. 500b1s Cont RU on SD-5. move annular, modify flow outlet. prep top drive, RU floor, complete all plumbing! electconnections. PJSM, NU diverter system, all related components. Accept Glacier rig:#1 this date, 1800 hrs. Troubleshoot DP elevators (hyd operation) PJSM. test diverter system, Perform fime /volume test I<oorney unit. Test successful, no re-tests. Witness waived Mr Lou Grimaldi AOGCC, PJSM. prepare floor for DP, rack /strap 4" DP. PJSM, PU 4" DP singles, stand bk In mast for spud. 20 stands bk at 0600 hrs. PJSM, MU BHA, RIH same.. Tag formation at 36 ft, drill :ahead 12 1/4 hole 36 -.150 ft ART = 4.5 hrs, AST = 0 hrs Difficult drlg, rock /boulders, bit torquing, work. pipe, clean weilbore. Spud well 7/13/2006 at 36 ft, 0730 hrs. 14:00 -14:30 0.50 CIRC_ .MUD SURDRL C/C mud, clean weilbore for trip. 14:30 - 15::00 0.50 TRIP_ BHA_ SURDRL PJSM, flow check, POH for BHA. Tight at 120 ft, work through. 15:00 - 15:30 0.50 REPAIR RIG_ SURDRL Replace top drive hose. 15:30 - 18;00 2.50 TRIP_ BHA_ SURDRL MU dretnl asst', surface test, RIH same. Ream bridge of 120: ft. 15 ft fill, no gain /loss. 18:00 - 05x00 11.00 DRILL_ ROT_ SURDRL Drill ahead 12 1/4 hole dretnl, 150 - 802 ft ART = 0 hrs., AST = 5,5 hrs Continued difficult drlg, torque /bouncing /boulders. Work tight corm's No gain /loss 05:00 - 05:30 0.50 CIRC_ MUD SURDRL Circ for wiper trip I saver sub change to 4" HT, no gain !loss. 05:30 - 06:00 0.50 TRIP_ WIPR SURDRL PJSM, POH wiper tripto conductor at 91 ft. Depth 560 ft of 0600 hrs. 7/15/2006' 06:00 - 08;00 2.00 CHANG EQIP SURDRL PJSM, change saver sub to HT Thread for DP. 08:00 - 09;00 1.00 TRIP_ WIPR SURDRL Flow check, PJSM, RIH wiper trip. Wellbore unstable, wash /ream various depths 126, 510, 660, 802 ft. Precaution wash to btm, 15 ft fiU (large cuttings, rock, sand, clay at shaker) clean at btms up. D9:00 - 03;00 18.00 DRILL_ ROT_ SURDRL Drill ahead 12 1/4 hole dretnl 802 -1633 ft (Csg pt) No abnormal torque /drag / swab I gain /loss. ART= 5.6 hrs, AST = 7 hrs WOB 20, RPM. 80, 5PP 1550, SPM 318, PrintBtl: 11/2812007 723:39 AM Marathon. Oil Company Rage z of ~ ®perations Summary Report Legal Well Name: SUSAN DIONNE 5 !Common Well Nam e: SUSAN DIONNE 5 Event Name: ORIGINAL DRILLING Contractor Name: GLACIER DRILLLNG Rig Name: GLACIER DRILLING Date I From - To ( Hours ` Code Sub ~ phase Start: 7/11 /2006 Spud.. Date: 7/13/2006 End: 8!5/2006 Gratap: 5!2006 ~ 09:00 - 03:QO ~ 18.00 ~ DRI LL_ ~ ROT_ ~ SURDRL 03:00 - 04:00 1.00 CIRC_ MUD_ SURDRL 04:00 - 05:00 1.00 TRIP WIPR SURDRL OS:QO - 06:00 1.UIJ TRIP WIPR SURDRL 06:00 - 07:30 1.50 TRIP WIPR SURDRL 07:30 - 08130 1.00 CIRC_ MUD_ SURDRL 08:30- 09:00 0.50 TRIP_ WIPR SURDRL 09:00 -12:00 3.00 REPAIR RIG_ SURDRL 12:00 - 13:00 1.00 TRIP WIPR SURDRL 13A0 - 15:00 ~ 2.00 ~ TRIP_ ~ VdIPR (SURDRL Rig Release: Rig Number: 1 Description of Operations GPM 620 Up 60, pn 50, Rot 55 C/C mud for wiper trip. PJSM, flow check, POH wiper trip to conductor at 90 ft. Wcrk pipe at 780, 290 ft. PJSM, flow check, RIH wiper trip.. Depth 160 ft at 0600 hrs. Cont. RIH wiper trip, rotate through bridge at 802 ft, 816, 1420 ft. precaution wash 60 ft to btm, 15 ft fill. C/C drlg fluids, large pieces coal ,shales, sand to surface. Cont circ, shaker clean. Carbide / Hi vis sweep indicates gauge hole.. PJSM, flow check, POH wiper trip (due to continued unstable weilbore)' Discover bad drlg line. Flow check, slip /cut drig line at 1307 ft. Flow check, PQH wiper trip to conductor shoe. Normal drag,. no swab /gain !loss. Flow check, RIH wiper trip. Tight at 802 ft. Cont RIH, precaution wash 60 ft to btm, 3 ft fill. Wellbore good condition. 15:00 - 15':30 0.50 DRILL. ROT_ SURDRL Drill ahead 3 ft to 1636 ft addtnl rathole for cs due to fill 15:30 -16x30 1.00 CIRC_ MUD_ SURDRL C/C drlg fluids, Hi-Vis sweep indicates gauge hole 16:30 - 17:30 1.00 TRIP_ DP_ SURDRL PJSM, flow check, POH for 9 5/8 csg. Wellbcre good condition. 17:30 - 21:00 3.50 PULD BHA_ SURDRL Flow check, lay do dretnl assy,startd bk remainder in mast. 21:00 - 23:00 2.00 RURD ~ CSG_ SURCSG PJSM, place csg equip to rig floor, RU same. 23:00 - 00:00 1.00 RUN CSG_ SURCSG PJSM, MU shoe track, thread lock alt corm's. Guide shoe, 2 Jts 9 5/8 L80 BTC 40# csg, float collar. Check floats, floats holding. RIH same. 00:00 - 03:30 3.50 RUN_ CSG `SURCSG Cont RIH 9 5/8 csg to 1630 ft. Take wt at 820 ft, work through. Wash 40 ft to btm, 15 ft fill. 03:30 - 04:30 1.00 CIRC_ MUD_ SURCSG CIC fluids, large coals at shaker initially, tort circ clean. 6 bpm 230 psi 04:30- 05:00 0.50 PUMP_ CMT_ SURCSG P}SM, MU cmt hd, connect lines,. 05A0 -06:00 1.00 PUMP_ CMT_ SURCSG . Commence cmt 9 5/8 csg: Test lines 2500 psi, Pump 40 bbls spacer.! preflush at 0600 hrs: 7/17/2006 06:00 - 08:00 2.00 PUMP_ CMT_ SURCSG Cont. cmt 9 5/8 csg: Mix / pump cmt (180 bbls, 404 sks,17ppg, Type 1). Release plug, confirm plug dropped, .displace with 118 bbis mud. -.Bump plug wifh 875 psi / 5 min:, bleed, floats holdimg. Note: GIP at 0756 Mrs, lose circ{5 min) 75 bbls away, reduce rate to 2 bpm, regain circa Returns varied, s0 - 100% remainder job.. No recip, 30 bbls 12 ppg cmt to surface. Large formation particles. fa shaker during. cmt, Leaning up at 50°!0 of displacement. ICP = 141 psi at 6 bpm, FCP = 345 psi at 1.5 bpm 08:00 - 09:00 1.00 RURD_ CSG. SURCSG PJSM, remove cmt hd, RO cmt equip, clear floor. 09:00 - 14:00 5.00 NUND ROPE SURCSG PJSM, ND BOPS while clean pits, flush lines, mix Flo-Prc mud.. 14::00 - 18:00 4.00 NUND WLHD SURCSG Remove SCL wellhead. Note cmt at cellar. '18:00 - 21:30 3.50 NUND WLHD SURCSG PJSM, install /test to 2500 psi, multi bowl wellhead. 21:30 - 06:00 8.50 NUND BDPE SURCSG PJSM, NU BOPS, all components. NU-flow nipple at O6t)0 hrs. 7/18/2006 06:00 - 09:30 3.50 :NUND BDPE SURCSG Cont, NU BDPE, all componerts. 09:30 - 16:30 7.00 TEST_ BODE SURCSG PJSM, test BDPE, floor valves, choke system, top drive, standpipe, pump lines 250 / 3000 psi. Repair kill tine check while test. No delay. Perform accumulator time /volume /press test. Pull test plug, set wear ring, .clear floor. 16:30 - 17:30 1.00 TEST GSG SURCSG PJSM, test 9 518 csg 1500 psi ! 30 min: Test successful, no re-tests. 17:30 - 01:30 8.00 PULD - DP - SURCSG PJSM, PU 4" DP, stand bk In mast for 8 1!2 hole. 01:30 - 04;00 2.50 PULD_. BHA SURCSG PJSM,. MU bit #2, BHA #2, RIH same. PnntaQ: 11/28/2007 7:23:39AM ~' Marathon Oil Company Page 3 of S Operations Summary Rep®rt Legal Well Name: SUSAN DIONNE 5 Common Well Name: SUSAN DIONNE 5 Spud Date.; 7/13/2006 Event Name`.. ORIGINAL. DRILLING Start: 7/11!2006 End: 8/5/2006 Contractor Name: GLACIER DRILLING Rig Release: Group.: Rig Name: GLACIER DRILLING. Rig Number: 1 Date From - To Hours Code C de Phase Descriptidn of Operations 7/18/2006 04:00 - 05:00 1.00 TRIP_ DP SURCSG Follow BHA with 4" DP to 800 ft. 05:00 - 06c00 1.00 CIRC_ MUD_ SURCSG Cire /surface test MWD. No pulse. 7/19/2006 06:00 - 06:30 0.50 TRIP_ DP_ SURCSG. Cont.R1H 4" DP to float collar at 1545 Ft 06:30 -11:00 4.50 DRILL_ CMT_ SURCSG Drill cmt /float equip 1545 - 1636 ft Dense cmf at shoe track/shoe 1.1.:00 - 11:30 0.50 DRILL_ ROT_ SURCSG Drill 20 ft 81/2 hole to 1656 ft for FIT ART=.S hrs 11:30 -12x30 1.00 CIRC MUD_ SURCSG Flow check. Displace wellbore with Flo-Pro mud system. 12:30 -13:30 9.OQ TEST_ LOT_ SURCSG Perform FIT, 3.11 psi surface press = 14 ppg EMW. 13:30 - 15:30 2.00 DRILL - ROT - IN1 DRL . Drill ahead 8 1/2 hole dretnl 1656 - 1740 ft. MWD failure, will not pulse. ART = .5 hrs 15:30 - 16:00 0.50 TRIP DP INIDRL PJSM, flow check,: POH 4" DP forMWD to BHA. 16:00 -17:30 1.50 TRIP_ BHA_ INIDRL Flow check, LD MWD. No visual defects. 17:30 - 19:00 1.50 TRtP_ BHA. IN1DRL MU new MWD, RIN same, Surface test, MWD pulsing.. 19:00 - 19;30 0.50 SERVIC RIG_ IN1DRL Service rig 19:30 - 20:00 0.50 TRIP_ DP_ 1N1DRL Flow check, RIH 4" DP, precaution wash 30 ft to 1740 ft no till 20:00 - 06:00 10.00 DRILL_ .ROT INIDRL Drill ahead 8 1/2 hole dretnl, 1740 - 2288 ft Art = 4.2 hrs, AST =1.8 hrs. 7/20/2006 06x00 - 06:00 . 24.00 DRILL_ ROT_ INIDRL Drill ahead 8 1/2 hole dretnl, 2288 - 3923 ft Connections free, no torque /drag.. No gain /loss. ART = 13.8 hrs, AST = 2.6 hrs, Max gas 148 units. WOB 7; RPM 70, 5PM 251, SPP 1550, GPM 500 Up 100, Dn 50, Rot 65 7/21/206 06:00 - ©3:30 21.50 .DRILL ROT_ IN1DRL Drill ahead 8.1/2 hole dretnl, 3932 -::4800 fk (Csg depth) ART = 8.1 hrs, AST = 5.9 hrs Difficult sliding at 4200 ft, add 3% Dube-tex, drag reduced. Connections. free, no torque./drag, no gain /loss. WOB 10, RPM 70, SPM 255, SPP 1800, GPM 500 Up 100, Dn 60, Rot 75 '03:30 - 05:00 1,50 CIRC_ .GELD INIDRL. C/C fluids, pump Hi Vs sweep (slight increase cuttings), pump wt pill for #rip. 05:00 - 06:00 1.00 TRIP_ WIPR INIDRL. PJSM. flow check, POH wiper trip to 9 518 shoe. Increased drag at 4100, 25K over: No swab t gain !loss. Depth 4030 ft at 0600 hrs. 7/22/2006 06:00 - 12:30 6.50 TRIP_ WIPR INIDRL Cont.. POH wiper trip. Work /back ream various intervals. 4030 - 2340 ft. Large quantity cuttings return (wall cake, coals, shale slivers) while back reaming. No swab /gain /losses. Wellbore free 2340 to shoe at 1630 ft. Cont POH to BHA. 12:30 -14:00 1,50 PULD BHA_ IN1 DRL PJSM, flow check, LD dretnl assy, stand bk HWDP. 14:00 -14:30 0.50 SERVIC RIG IN1DRL Service rig 14:30.- 15:30 1.00 PULD BHA IN1 DRL PJSM, MU BHA #4, Bit #3RR1 (tri-cone) ,flow check, RIH same. 15:30. 18:00 2.50 TRIP_ WIPR IN1 DRL Follow BHA with 4" DP'to 4800 ft, precaution wash 30 ft, no fill. No do drag, no gain /loss. Wellbore free. 18:00 - 22;30 4.50 CIRC_ MUD_ INIDRL C/C fluids /wellbore. Btms up brings large amounts cuttings return. Hi-vis sweep brings addtnl 10%, final sweep brings min returns. Wellbore clean. Trip gas 85 units. Fluid caliper =gauge hole. Pump wt pill, drop rabbit. 22;30 - 02:00 3.50 TRIP_ DP_ IN1DRL PJSM, POH 4" DP to BHA (SLM}for E-logs. Wellbore good. cond. Max 15K drag. No swab./ gain /loss. No earese#ion SLM. 02;00 - 03:00 1.00 TRIP_ BHA_ 1N1 DRL Flow check, stand bk BHA. 03:00 -.06:00 3.00 PULD LOG_ IN1EVL PJSM, place E-log equip rig floor; RU same. PU shuttle asst'. 7/23/2006 06;00 - 08:00 2.00 PULD_ LOG_ IN1 EVL Cont. RU E-log / shuttle asst'. 08:00 -12:30 4.50 TRIP DP IN1 EVL PJSM, flow check, RIH shuttle assyto 4800 ft. Normal do drag, no bridge, no fill.. Printed: 11!26/2007 7:33:39 AM Marathon.. Oil Company Page 4 of 8 Operations Summary.Report j Legat Well Name: SUSAN DIONNE 5 , Common WeU Name: SUSAN DIONNE 5 Spud. Date: 7/13/2006 Event Name: ORIGINAL DRILLING Start: 7/1.112006 End: 8/b/2006 'Contractor Name:. GLACfER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date from - To Hours Cade Phase Description of Operations Code 7123/2006.. 12:30 - 13:30 1.00 CIRC^ MUD_ IN1 EVL CBU, POH to 4684 ft, deploy messenger tool, pump wt pill: -13:30 - 18100 4.50 LOG_ OH_ IN1 EVL POH 4!' DP logging up, quad combo, 4785 - 227 ft. Wellbore good cond. 18:00 - 21:30 3.50 PULD! LOG_ IN1 EVL Flow check, Lay do shuttle. BHA / E-log equip.. 21:30 - 23:30 2.00 RURD_ CSG_ INICSG PJSM, set test plug, change to 7" rams, test door seals 3000 psi, pull test plug. 23:30 - 00:30 1.00 RURD_ CSG_ INICSG PJSM, place csg run tools rig floor, RU same. 00:30-..04:00 3.50 RUN CSG_ INICSG Commence RIH 7" csg: Assemble shoe track, thread lock all corm's. Guide shee, 2 jts (7" L-80, 26#, BTC) float collar. Check floats, floats holding. Cont RIH 7" csg, to 690 ft. 04:00 - 05:00 1.00 REPAIR. EOIP IN1CSG Weatherford electr+c tong unit arcing to csg /rotary table. Replace with diesel powered unit. 05:00 - 06:00. 1.00 RUN_ CSG. 1N1 CSG Flow check, resume RIH 7" csg. to 1400 ft at 0600 hrs: 7/24/2006 06:00 - 07:00 1.00 RUN GSG'_ IN1 CSG. Cont R!H 7" csg to 1626 ft. 07:00 - 08:30 1.50 SERVIC EQIP INICSG Note electrical arcing at csg /rotary area. Troubleshoot power tongs, rig elect system. Discover BJ unit not grounded. Ground unit, no arcing. 08:30- 15:30 7.00 RUN_ CSG_ INICSG Resume RIH 7" csg, precaution wash last 2 jts to btm. Na fill. Circ at 1626, 2950 (tight hole, large amounts cuttings to surface) 3922 (tight hole,.. cire clean). Final depth (shoe 4788, float 4702) Total 108 jts 7", L-80, 26#, BTC. 15:30 - 19;00 3.50 PUMP_ CMT_ INICSG Commence cmt7" csg: Pump 5 bbls H2o, test lines 3500 psi. Mix /pump 30 bbls MCS sweep 10 ppg Mix /pump lead, 254 sks, 111.7 bbls G, yid 2.477, 12.5 ppg. Mix pump tail, 197 sks, 40.9 bbls, G, 15.8 ppg. Drop plug, confirm dropped, displace with 177.1 bbls Brig mud. Bump plug wifh1744 psi, hold 5 min, bleed, floats holding. CIP 4840 hrs, approx 15 bbls contaminate, 5 bbls cmt returns: Re-c±p entire lob, ICP = 327 psi / 5 bpm, FCP = 851 psi / 1 bpm, 19:00 - 20:30 1.50 TEST_ WLHD INICSG Install pkf, test 5000 psi 110 min, test successful, no re-test.. 20:30 - 22:30 2.00 CLEAN_ TANK INICSG Clean pits (Trace cmt /contaminate) 22:34 - 01:00 2.50 RUNPU WBSH INICSG Install wear bshg, change rams, test door seals:. 01:00 - 06:00 5.00 PULD;` DP_ INICSG PJSM, PU 4" DP, stand bk to mast for drill out.. 7/25/2006 06:00 -09:00 3.00 PULD_ DP_ INICSG Cont PU 4" DP, stand bk to mast for drill out. 09:00 - 10:00 1.00 TEST_ BOPE IN1GSG PJSM, RU for test ROPE 10;00 -13:30 3.50 TEST_ ROPE INICSG PJSM, replace non. opening HCR valve:. 13:30 - 19:00 5:50 TEST_ ROPE: INICSG PJSM,. test ROPE, all related components 250/3000 psi. 19:00 - 20:00 1.00 TEST_ ROPE INICSG PJSM,. replace leaking 1t30P at top drive. Re-test. Test successful:.. 20:00 - 20:30 0:50 TEST_ BODE IN1CSG Pull test'plug, install wear ring.. 20:30 - 22:00 1.50 TEST_ CSG_ INICSG PJSM, test 7" csg 2500 psi / 30 min. Test suecessful,,no re-tests. 22:00 - 01:00 3.00 PULD BHA_ INICSG PJSM, assemble & 118 drill out BHA, RtH same. 01:00 - 03:00 2.00 TRLP_ DP_ INICSG Follow BHAwith 4" DP to float collar. Tag at 4702 ft. 03:00 - 05:00 2.00 DRILL_ CMT_ IN1CSG Commence drill shoe track /shoe / emt to 4800 ft. Hard cmt at hoe track /under shoe. No voids. 05:00 - 05:30 0:50 DRILL. ROT_ INICSG Drill ahead 6 1!8 hole 4800 - 4820 far LOT: RRT = .5hrs, AST = 0 hrs 05:30 - 06:00 0.50 CIRC_ MUD_ IfV1CSG Circ, displace wellbore with FIo-Pro mud system. 7/2612006 06:00 - 07:00 1:00 CIRC_ MUD_ IN1C5G Cont. displace wellbore with FIo-Pro mud system. 07::00 - 08:00 1.00 TEST_ LOT_ IN1CSG PJSM, perform LOT, surface press 1225 psi = 16.5 EMW No leak off, cunt hold 30 min, no press drop. Bleed, clear floor. 08:00 - 09;00 1.00 CIRGT MUD PR1 DRL Attempt POH, extreme pipe drag./ chattering, add 3°1o LubeTex. Prir~ted€ 11f281200T 7:23:39 AM Marafihon tOii Company hags 5 of s Operations Summa~yr F~eport ' Legal Well Name: SUSAN DIONNE 5 Common Well Name: SUSAN DIONNE 5 Spud. Date: 7/13/2006 Event Name: ORIGINAL DRILLING Start: 7/11/2Q06 End: 8/5/2006 Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date (From - To I Hours I Code I Co e I Phase L Description of Operations. 08:00-09:00 1.00 CIRC MUD_ PR1DRL 09:Oq- 12:30 3.50 TRIP_ DP_ PRIDRL 12:30 - 14:00 1.50 PULD_ BHA_ PR1 DRL 14:00 -16100 2.00 TRIP_ DP PR1 DRL 16:00 - 17:00 1.00 REPAIR RIG_ PR1DRL 1:7:00- 17:30 0.50 WASH FILL PRIDRL 17:30 - 06:00 12.50 DRILL_ ROT_ PR1 DRL ~ 7/27/2006 { 06:00 -12:30 ~ 6.50j DRILL_ ~ ROT_ ~ PR1 DRL 12:30-14:30 2,00 TRIP DP_ PRIDRL 14:30- 15;00 0.50 SERVIC RIG_ PR1DRL 15:00. - 16:00 1.00 TRIP_ DP_ PR1 DRL 16:00 - 06:00 14.00 DRILL_ ROTS PR1 DRL 7/2$12005 ~ 06:00 - 12:00 ~ 6A0 ~ DRILL ~ ROT_ ~ PR1 DRL 12:00- 15:00 ~ 3.00 DRILL_ ~ROT_ (PR1DRL 15:00 -17:00 2.00 TRIP DP PR1DRL 17:00 -18:00 1.00 TRIP_ DP~ PRIDRL 18:00 -.00:00 6.00 DRILL_ ROT_ PRIDRL 00:00- 06:00 ~ 6.00 ~ DRILL_ f ROT_ ~ PR1DRL ~ 7/29/2006 ~ 06:00 - 09:30 E 3.50 ~ DRILL_ ~ ROT_ ~ PR1 DRL 09:30- 11:00 1.50 TRIP DP PRIDRL 11:00 - 11;30 0;50 TRIP_ DP_ PRIDRL 11:30-12:00 0.50 DRILL_ ROT_ PRIDRL 12:00 - 18:00 ~ 6:00 ~ DRILL_ ~ ROT_ ~ PR1DRL 18:00 - 00:00 I 6.001 DRILL_ ~ ROT_ PRIDRL 00:00 - 06:00 ~ 6.00 ~ DRILL_ ~ ROT_ ~ PRIDRL Drag reduced, prepare POH. .PJSM, POH 4" DP to BHA. Flow check, MU BHA #6, bit#5, RIH same, surface test MWD. Flow check, follow BHA with 4" DP to 7" shoe. PJSM, service rig, repair disc brake drwks Precaution wash cmt !new hale (6 1/8) 4800 - 482D. Drill ahead 4 3!4 X 7 hole, dretnl, 4820 - 5314 ft ART = 3.7 hrs, AST = 3.7 hrs Drill Slide Survey 4 3!4 x 7 Hole F- 5314'-5644' Up Wt. 90 Dn. Wt. 60 Rt. Wt. 75 Tq. 6-7K. Art= 2.4 Ask = 2.3' POOH.T- 4308'( 200psi Drop In Pump Pressure.} Found. Wash Out In Stand #56 Slip Area. Service Rig. Crown, Blocks, Dwks And Top Drive RIH To 5644' Drill Slide Survey 4 3/4 x 7" Hole F-5644-6365' Up Wt. 105 Dn Wt.60 Rt Wt. 76 Tq. 6-7 Art =6.2 Ast= 3.6 -Drill Slide Survey 4 3i4 x 7 Hale F-6318'-6764' Up Wt.120K Dn Wt. 65K Rt. 86K Tq.-5-7K Art= 5hr Ast=O PJSM; Dnll Slide Survey 4 3/4 x 7 Hole F-6764'-6886' Up Wt.120K Dn Wt. 65K Rt VVt.87K Tq.-6-7K Art=1.4 Ast=.2 Check Flow POOH F-Washout, Lost 400 PSI Drill String Pressure Found Hole 726' Down.Change Out Joint, Finish POOH For Wiper Trip To 5560' Tight At 6200' & 5720' Trip In Hole T-6819' And Wash Down To 6886' Drill Slide Survey 4 3/4 x 7 Hole F-6886'-7129' Up Wt. 125K Dn. Wt 65K Rt. Wt.88K Tq.-6-7K ..Art=3.3 Ast=1.5 PJSM; Drill Slide Survey 4 314 x 7 Hole F-7129'-7500' lJp Wt. 128f< Dn. Wt. 70K Rot.Wt. 96K Tq: 6-7K Art-6 Ast=O( Note Ran Centerfuge Van Mud Wt Int 9.6 Final 93+ ) Drill Slide Survey 4 3/4 x 7 Hole F-7500'-7682' Up Wt. 134K Dri wt. 70K Rat Wt. 98K Tq.=6-7K Art=32 Ast=O Check Flow POOH F-Washout Lost 20D PSI: Drill String Press. Found Hole 866' Dawn Change Out Jt. Trip In Hoie To 7626' And Wash Down to 7682' Drill Slide Survey 4 3/4 x 7 Hole F-7682'-7689' Up Wt. 134K Dn wt. 7QK Rot Wt. 98K Tq.=6-7K Art=:2 Ast=O PJSM: Drill Slide Survey 4 3/4 x 7 Hole F-7689'-7938' Up Wt. 140K Dn Wt. 70K Rat Wt. 100K Tq.=7-8K Art=4J Ast=O Pump High Visc.Sweep At 7813' Got Back 200 °1a More Cuttings .Drill Slide Survey 4 314 x 7 Hole F-7938'-81:32' Up Wt. 145K Dn Wt. Rt. Wt. 105K Tq:=7-8K Art=3 Ast=.9 Drill slide Survey 4 314 x 7 Hole F-8132'-8269' Up Wt.150KDn Wt.75K Rt Wt.106K Tq.=6-7K 11/?8!2007 7:?3i39AM Marathon Oil Company wage 6 of 8 Operations Sumr-raary Rep®rt Legal Well Name: SUSAN DIONNE 5 Common Well Name: SUSAN DIONNE 5 Spud Date: 7/13!2006 Event Name: ORIGINAL DRILLING Start: 7!11!2006 End: 8J5/20Q6 Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date from - To Hours Code Code. Phase Description of Operations 7/29/2006 00:00 - 06:00. 6.00. DRILL_ ROT_ PRIDRL Art=2.1 Ast=1.4 7/30/2006 06:00 - 08:00 2.00 DRILL_ ROT_ PR1 DRL Drii14 314" X 7" Hole F- 8269' - 8279' Up Wt. 150K Dn Wt 75K Rt 1Nt 106 Tq=6-8K Art=O Ast=1.0 08:00 - 09:00 1.00 CLNOU OHS PRIDRL Pump 28 Bbl. Hi Visc. Sweep(Got Back 2Q0% More Cuttings Retum Than Normal) Circ. Due To HVY: Bluffing Coals & Sand. 09:00 - 12:00 3.00 DRILL_ ROT_ PR1oRL Drill 4 314" x 7" Hole F-8279'-8373' Up Wt. 152K Dn Wt. 72K Rt Wt. 108K Tq=7<8 1/2K Art=1.3 Ast= .5 12:00. - 13:00 1.00 DRILL ROT_ PRIDRL PJSM; Drill 4 314" x 7" Hole F-8373'-8406' Up Wt, 155K Dn Wt. 75K Rt Wt. 11OK Tq=8-9K Art= Ast=.5 13:00 - 14::30 1.50 TRIP DP PR1 DRL Check For Flow POOH F/ Washout Lost 300 PSI Drill String Pressure Found: Hole At 124&' (hangs Out Joint .14:30 - 15:00 0.50 SERVIC RIG_ PR1DRL Service Rig And Top Drive,Grease Crown 15:00 - 15:30 0.50 TRIP DP_ PR1 DRL Trip. In Hole To 8376' And Wash Down To 8406' 15:30 - 18:00 2.50 DRILL... ROT_ PR1 DRL Drill 4 3/4" XT Hole F840ii`-8483' Up Wt. 1551( Dn Wt. 75K Rt Wt 110K Tq=8-9K Art=2.7 Ast=O 18:00 - 20:30 2.50 DRILL_ ROT_ PR1 DRL Drill 4 3/4' x 7" Hole F-8483'-8590' Up Wt. 155K Dn Wt. 75K Rt Wt.110K Tq=8-9K Art=2.0 Ast=O 20:30 - 00:30 4.00 TRIP DP PR4DRL Check For Flow POOH F! Washout Lost 300 PSI Drill String Pressure Pull To 5341' Found Washout At 3809' Laydown Bad Joint 00:30 - 04:00 3.50 TRIP_ DP_, PR1DRL Cont. POOH. From 5081` For Bit Change: No Gains Loss Correct Hole Fill 04:00 - 05:30 1.50 TRIP BHA_ PR4DRL POOH With BHA And Break Out Bit .05:30 - 06:00 0.50 _ TRIP_ BHA_ PR1 DRL Make Up BHA And Bit RIH. 7/31/2006 06:00 - 06:30 0.50 TR[P_ BHA PR10RL PJSM;. TIH W/ Bha # 7 06:30 - 08:30 2.00 TRIP_ DP_ PR1 DRL TIH F- 795' W/ 4" D/P To 4787 No Gain/ Loss 08:30 - 09:30 1.00 CUT_ 'MIRE PR1 DRL PJSM; Slip Drilling Line. 09:30 - 11:30 2.00 TRIP_ DP_ PR1 DRL Cont. RIH F 4787 - 8559' Wash And Cleah out To 8590` No Fill. No Gain Goss Correct. 11;30 -12:00 0.50 CIRC MUD_ PR1 DRL Pump. Hi' Vis Sweep At 8590' Circ Gond. Mud Hole. 12::40 -13:09 1.00 DRILL_ ROT_ PR1 DRL. Drill Survey F- 8590'- 8624' 300psi prop In Pump Pressure. Art=.9hr. Ast=D Up Wt. 155 Dn Wt. $0. Rt. 112 TQ 7000 - 8500 13:00 - 15:00 2..00 TRIP_ DP_ PRIDRL .POOH F- 8624' T- 7720' Found Wash Out 904' In. Stand # 113. RIH To 8624' 15:00 - 00:00 9.00 DRILL ROT_ PR1 DRL 17ri11 Survey F- 8624' -8937" Up Wt. 160K Dn Wt. 85K Rt Wt. 118K Tq=8000-9000 Art=7.5 Ast=O No Gains No Loss 00:00 - 00:30 0.50 REPAIR. RIG_ PR1 DRL Replace Hyd. Cylinder on Rig Elevators 00:30 - 06:00 5.50 DRILL_ ROT_ PR1 DRL Drill Survey F-8937-9100' Up Wt 170K Dn wt. 77K Rt Wt.119K Tq =7000-8500 Art=2.1 Ast=1.3 8!112006 06:00 - 19:00 13.00 DRILL_ ROT_ PR1 DRL Dr11 Survey F- 91:00'- 9600' TD Up Wt. 185K Dn Wf.90K Rt Wt. 1281<Tq=8000-9000 Printed: 11/2812007 7:23:39 AM Marathon O{ .Company Page 7 of 8 Operations Summary Rep+~rt Legal Well Name: SUSAN DIONNE 5 Common Well Name: SUSAN DIONNE 5 Event Name: ORIGINAL DRILLING Contractor Name: GLACIER DRILLING Rig Name: GLACIER DRILLING Qate From - Ta Hours Code C d Phase 8/1/2006 .06:00 - 19:00 13.00 DRLLL_ ROT_ PR1 DRL 19:00 - 21:00 2.00 CIRC MUD PR1 DRL :00 - 02:00 I 5.001 TRIP_ DP_ - 02:30 ( 0.501 SERVIG RIG I PR1 DRL - 05:00 2.50 TRIP DP_ PR1 DRL 05:00 - 06:00 ~ 1.00 ~ CIRG„ MUD ~ PR1 DRL 06:00 - 08;00 ~ 2.00 ~ CIRC_ MUD_ ~ PR1 DRL 08:00 - 15;:30 ~ 7.50 ~ TRIP_ DP_ ~ PRIDRL 15:30 - 16;30 ( 1.00 ~ TRIP_ ~ BHA ~ PR1 DRL 16:30 - 20:30 ~ 4.00 ~ TRIP_ ~ EQIP ~ PR1 EVL 20:30 - 04:30 ~ 8.00 ~ TRIP_ (EQIP ~ PR1 EVL 04:30 - 06;00 ~ 1.50I CIRC_ I MUDS I PRIEVL 8/3/2006 06:00 - 06:30 0.50 CIRC,_ MUD_ PR1 EVL 06:30-07.:30 1,00 LOG. OH_ PR1EVL 07:30-13:00 5.50 LOG_ OH_ PRIEVL 13:00- 14:30 1.50 RUNPU ELEC PR1EVL 1:4x30 - 15:30 1.00 PULD_ BHA_ PR1EVL 15:30 -16:00 0.50 CLEAN_ RIG_ PRIEVL 16:00 - 20:30 4.50 WAITON ORDR PR1 EVL 20:30-21;30 1.00 PULD LOG PR1EVL Spud Date: 7/13/2006. Start: 7/11/2Q06 End: 8/5/2006 Rig Release; Group: Rig Number: 1 Description of Operations Art=9.55 Ast=O Circulate For Samples, Pump High Visc. Sweep,Circulate Hole Clean For wiper Trip. PJSM; Trip Out Of Hole For WiperTrip 9600'- 478TTight Spots-8875'-8688' No Gain Loss, Correct Hole Fill. Service Rig and Top Drive,Crown,Drive Line Trip In HoleTo 9550' Hole Slick, No Gains Na Losses Up Wt.185K Dn Wt.90K Rt Wt.128K Tq=7000-8000 Wash Down To Bottom 9600'Circ.High Visc. Pill And Condition Hole For Logs. Circ 240stks 300gpm 2250psi. Note Tag 6' Fill. Circ Pump 2x Sweeps At 9600' Pump 240spm 300gpm 2150psi. Sweeps Returned with increase in Coals & Sand. Montior Well, pump Dry Job Note; Sweep Retumed As Caculated 12300Stks PJSM; POOH Drop Rabbit/ SLM. F- Laggs F-9600' No Gains Loss, Proper Hole Fill Tight Spot At 5825',SLM Out of Hole No Correction On SLM PJSM; Handle BHA Stand Back. HWDP Lay Down Directional Tools PJSM;Prepare and Pick-up Shuttle Load and Redress Shuttle Tools Trip In Hole With Shuttle Tools To 2500' Flow Test.. Shuttle At 2500',4612',7000`Rnd 9431'. TIH to 9592Tag 8' Fill. No Gain Loss. Correct Displacement Circ Wash To 9600' Pump Hi Vis. 27 Bbbl Sweep At 170spm 1450psi 146.. gpm At 9600' Sweep. Returned W/ Hoy Coals. Up To 1" Dia. Cont. Circulating Up Sweep At 9600' Pooh To 9583', Drop Messenger Dart/ Pump DepEoy Logging Tools Run Quad. ComboLoggng Tools Qn Shuttle System F-9600' - 3672` Pooh W/ 4° D/P F- 3672. To BHA Stand Back Hwdp. UD Shuttle Assy & Quad. Combo Logging Tools Clear And Clean Rig Floor Wait Dn Log Evaluation For MFT Pick Points.. Monitor Well PJSM; Rig Up Weatherford Wireline,Make up. MCG,MIM,and MIE 21.30 - 22:30 ~ 1.00 RUNPU~ELEC PR1 EVL Run In Hole W/ FMI,HMI, Logging. Tools. To 6700` Tagged Bridge 22:30 - 00;30 2.00 WORK ELEC PRIEVL Logging F-6700'-5972' Toots Hanging Up. POOH Unable To Pass 00:30 - 01 :D0 0.50 PULD_ LOG_ PR1 EVL 01:00 - 01:30 0.50 PULD_ BHA_ PR1 EVL 01:30 - 03:00 1.50 TRIP_ WIPR PR1 EVL 03:00 - 04:30 1.50 CUT_ WIRE PR1 EVL 04:30 - 06:00 1.50 TRIP WIPR PR1 EVL 06:00 - 07:00 1.00 TRlP DP PR1 EVL 07:00 - 09:30 ~ 2.50 ~ GIRC_ ~: MUD_. ~ PR1 EVL Lay Down Logging Tools And Rig Down Pick-Up BHA To Make Cieanout Run TIH {Wiper Trip}To 4750' No Gain/ Loss.. Cut and Slip Drilling Line TIH (Wiper Trip} F- 4750- 7500' Continue RIH To'9550't Wash To 9800' Tag. 2' Soft Fill. No Gain Loss.. Hole Slick. Note; Lost tong Die 4 112"Long In Hole. Circ Pump Hi Vis Sweep At 240spm 300gpm 1550psi. Hoy Coal/Sand Returns Over Shakers.. Run Centerfuge Van Intl Mud Wt, 9.8 Final MUV. Printed: 11/28/21)07 7:23:39 AM Marathon Oil Company Page 8 of 8 Operations Summary Report Legal Well Name: SUSAN DIONNE 5 Common Well Name: SUSAN DIONNE 5 Spud. Date: 7/13/2006 Event Name: ORIGINAL DRILLING Start: 7/11/2006. End: 8/5/2006 Contractor Name:. GLACIER DRLLLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date Erom - To Hours Code ode Phase bescription of Operations 8/4/20Q6 07:00 - 09:30 2.50 CIRG_ MUD_ PRIEVL 9.6. Girc. Until Shakers Cleand Up 09:30 - 16:00 6.50 TRIP_ DPT PR1EVL PJSM; Monitor WeU POOH F- Logs F 9600' - 8662' Pump KCI dry Job. Continue Pooh. F-8662' Std Back BHA. 16:00 - 16`.30 0.50 RURD_ ELEC PR1 EVL PJSM; WU Weatherford WLS To Run MFT Logging Program. 16:30- 1:8:30 2.00 RUNPU ELEC PRIEVL RIH W/ MFT Logging Tools On E- Line. To 6550'Try Working Thru Bridge No Go. Logging Tool Not Working 18:3fl - 20':30 2.00 RUNPU ELEC PR1 EVL POOH With Wreline Tools Remove One Centralizer.C/O To Smaller Pressure Pads Qn .MFT Tool 20:30 - 23:30. 3A0 RUNPU ELEC PR1 EVL RIH W/MFT Logging Tool Tag. Bridge At 8210' Check Tool, Working 23:30 - 06100 6.50 LOG_ Qh_ PR7 EVL Logging Pressure Points Up From 6878'-5331..' Monitor Well No Gains No'Losses 8/5/2006 06:00 - 07:00 1.00 tOG_ OH_ PR7 EVL Cont. MFT E- Line Logging. Log to :5242` 07:00 - 07:30 0.50 LOG_ OH_ PR1 EVL POOH w/ E- Line Logging Tools. 07:30 - 08:00 0.50 RURD_ ELEC PRIEVL R/D E- Line Lagging Tools. Go To Completion Event, rnnwu: r. ~~~oicw~ ~.eoaa n~r~ ~~ Marathon Oil Company Page ~ of 5 Operations Slumllniary Report Legal WeU Name: SUSAN DIONN~ 5 Common Well Name: SUSAN DIONNE 5 Spud Date: 7/13/2006. Event Name: ORIGINAL COMPLETION Start: 8/5/2006 End: 8/16/2006 Contractor Name;: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To Hours Code .Code Phase Description of Operations 08:00 -14;00 6.00 TRIP_ DP_ PR1CSG PJSM ; TIH W/ 4" Driilpipe (Wiper Trip To 9600' Wash Ream Clean Up At $243, 6870' 8220' Cont.. RIH To 9530' Wash Down To 9600' Tag 10' Fili 14;00- 17:30 3.50 CIRC MUD PRICSG Circ. Condition. Mud Pump30 Bbi. Hi Vise: Sweep At 300 GPM Monitor Well Pump Dry Job 17:30 - 02:00 8.50 TRIP. DP_ PR1 CSG PJSMt POOH F- 9600' Std. Back 75 Stds.,Lay Down 68 Stds:136jts Total. No Gain Loss. Hole Slick. 02;00 - 02:30 0.50 TRIP_ BHA_ PRICSG L/D Jars One Joint 4" hwdp. Clean :Rig Floor 02:30 - 05:00 2.50 RURD" CSG_ PR1 CSG PJSM; R/U Weatherford Csg. Tongs Tools. C/O Elevators Bails 05:00 - 06:00 1..00 RUN CSG PRICSG PJSM; M!U Shoe Track, Thread lock All Connections ( Shoe T 2 jts 41l212.60ppf L-80 Hyd 563 Float Collar. Ldg Collar) Cheek Floats. 06:00 - 12:30 6.50 RUN CSG_ 'PR1 CSG Contuine Rih W/ Prod.. Liner 4 1!2 1:2.60 ppf L-t30-Hyd 563 5004' Total 120jts. Set Pac Valve At 6984' 12:30 - 14;30 2.00 Rl1N_ CSG_ PR1 CSG PJSM; GO Bails & Elevators. 1.4:30 - 15:30 1.00 RUN CSG_ PRICSG P/U Liner Hanger, M/U BOT Rotating Cmt. Mead, Circ Liner Volume, Establish Parameters lJp Wt. 43k Dn. Wt=36 Rot, 48 Tq 4000 At 5004' 15:30 -1:6;30 L00 RUN_ CSG PR1CSG PJSM; Cont. Run 4 1/2 Liner On Drill Pipe F-5004'-6432' 16:30 - 17:30 1.00 CIRC_ MUD_ PRICSG Circ. Bottoms Up-6432'13 bbls. Min,-410 PSI,Up Wt -95K Dn. Wt: 54K,Hanging Wt.-58K 17:30 - 18;30 1.00 RUN_ CSG._ PRICSG Run In Hole With 41/2 liner On 4" Drill Pipe From 6432'-8059" 18:30 - 19:00 0.50 CIRC MUD_ PRICSG Fill Pipe-Break Circ. At 3 Bbls. Min.Up Wt. 130Kpn Wt.-62K Pump Press.=460 P51 At $059' 19:00- 19:30 0.50 RUN_ CSG_ PRICSG Run In Hole With 41/2 liner On 4" Drill Pipe F-8059'-8440' 19:30 - 20:00 0.50 RUN_ CSG PRICSG Work And WashThru'Bridges At 8440'-8450' Up Wt.150K Dn. Wt.75K 20:00 - 20:30 0:50 RUN_. CSG_ PR1G5G Run In Hole With 4 1/2 Liner On 4" Drill Pipe F-8450'-9563'Circ And Wash Down To 9600' 20:30 - 00:30 4.00 CIRC_ MUD_ PRICSG Circ. And Cond.. Mud Pump High Visc.Sweep Weil Bore Trying To Pack-Off Up Wt.154K Dn VJt.75K Hold PJSM; With BJ For Cmt. Job Clrc Until Shakers Cleaned Up. 00:30 - 01:00 0.50 RURD_ CMT_ PR1CSG Install CemenYHead Break Circ.3 Bbls. Min. 01:00 - 04:30 3.50 PUMP CMT_ PR1 CSG Pump 3 Bbis. Ahead Test Lines to 5000 PSI,Mix And Pump 20-Bbls MCS4 Spacer At 10.5-ppg/Mix And Pump 330-sks Glass G+10%BA-90+2.5%BA-56+.5%EC-1+5%SMS+.4%CD-32' +.1%ASA-301+.05%Static Free+1ghs FP-6L YIELD 2.019 10.681 gal/sk 4:35mn Pump Time 118.6 Bbls.tofal cmt. lost Returns After 83bbls Cmt. Displaced Drop Dart Displace W/81 bbis. dart stopped at PAC Valve Pressured to 2200 PSI to push Dart Thru Cont,To Displace To Landing Collar Pump1/2 Bbl. minLast 5 bbls. Plug Bumped W/ 119 Bbis. Pressed. to 2200 PSi Set Hanger Slacked 80K Down on Hanger Cont to Pressure up to 2900 P51 Open PAC Valve PAC Valve Opened ,and Giosed Release Hanger and Pick Up 16'. Circ Bottoms Up. Cmt In Place 0309 hrs 04:30 - 05:00 0.50 RURD_ CMT_ PRICSG Lay-Down Cement Head and Rig Down Cementers 05:00 - 06:00 1.00 TRIP_. DP~ PR1CSG POOH W/ Drill Pipe and 80T Tools. Top Of 4 1/2 Liner Hanger at 4591'- Shoe At 9595' F/C 9510' UC 9468.:13' .06:00 - 08:30 2,50 TRIP_ DP PR1 CSG Cont. Paoh L/D BOT Liner Running Tooi, f'nnte°r Tiiz°~zuvi rza:aannn Marathon Oil Company Page 2 of 5' Operations Summary ~epolrt Legaf 1Nell Name:: SUSAN DIONNE 5 Common Well Name: SUSAN DIONNE 5 Spud Date;: 7/13/2006 Event. Name: ORCGINAL COMPLETION Start: 8/5/2006 End: 8/16/2006 Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number:. 1 Date From - To Hours Code Cod Phase Description of Operations 8/7/2006 0$:30 - 12:00 3.50 RURR_ OTHR PR1 CSG RN To Run 2 7/S DriNppe: Unload Drillcollars brill Collars, Drillpipe, Mud Motor,Jars strap Drift Bha. 12:00 -13:30 1.50 TRIP BHA PRICSG M!U 3 1/8 Mill Clean Out Bha RIH 13:30 - 21x30 8.00 TRIP DP_ PRICSG PJSM; Strap Drift P/U 2 7/8 Drillpipe. 21:30 - 22:00 0.50 CIRC_ MUD PR1 CSG Fil PipeAnd Rotate Thru Top Of Liner at 4590' Up Wt 65K Dn Wt.34K .22:00 - 23:00 1.00 TRIP_ DF' PR1CSG RIH Picking Up 2 7/8 Drill Pipe TO 5104' 151: Joints Total P/U 23:00 - 23:30 0.50 TRIP_ DP_ PR1 CSG .Change Elevators And Tongs To Ruh 4" DP 23:30 - 01.:30 2.00 TRIP! DP PR1CSG Trip In Hole With 4" Drill Pipe to Mill Out PAC Valve 01:30 - 02:00 0.50 MILL_ PLUG PRICSG MIII PAC Valve Work Up And Down Thru Valve RiH To 7000' Up Wt. 100k Dh Wt50k 02:00 - 02:30 0.50 CIRC_ MUD_ PRICSG Gire.Bottoms Up At 110spm 1600psi 135gpm Shakers Clean 02:30 - 03:30 1.00 TRIP_ DP PRICSG Trip Out 4f Holo With 4" Drill Pipe To 2 7/8 Drill Pipe 03:30 - 05:30 2.00 RURD_ OTHR PR1 CSG RJD DD Tongs R/U C Tongs Fort 7!8 Drillpipe 05:30 - 06:00 0.50 TRIP_ OP_ PRICSG PJSM; Pooh w/ 2 7/8 D./P F- 5100' 8(8/2006 06:00 -1:1:00 5.00 TRIP_ OP~ PRICSG PJSM; Pooh W 2 718 Drillpipe F-4350'. UD Mill BHA. 11:00 - 11:30 0.50 RURD_ ELEC PRICSG PJSM; RIU Expro WLS To Run E-line. Gauge Ring /Junk Basket. 11:30 - 1.8:00 6.50 RUNPU EI.EG PR1 CSG RIH W/ Gauge Ring (3.750") OD /Junk basket On E- line Attempt To Enter Liner Top At 4590' No Go: POOH W/ Gauge Ring/Junk basket. LID 3.750" G/R P/U 3.625" G/R RIH On E- Line. Work Through Liner Top. Tag Up At 9431' (WLM) 3T Above Landing Collar At 9468' Ponh . L/D Ga. Ring And Junk Basket. R/U Gamma Ray Cement/ CBL Tools: RIH. Run. CBL Good Cmt. Bond F 8048'- 9210' .Intermittent 18:00 - 22:00 4.00 22:00- 00:00 I 2.001 RUNPi 00:00 - 02:00 2.00 RURD. 02:00 - 04:30 2.50 TRIP_ 04:30 = 06:00 1.50 RURD; 8/9/2006 06:00 - 07:30 1:50 PUMP 07:30 - 08:00 ~ 0.50 ~ PUMP, 08:00 - 09:00 { 1.00 ~ PUMP. 09.00 - 09:30 I 0.50 RURI 09:30 - 1:3:30 4.00 TRIP .ELEC PR1CSG PJSM; RIH W/ #10 Setting And Bridge Plug: Posi~on And Set Plug At 5750' POOH ELEC PR1CSG PJSM;RIH W/ Armed Perf Gun Position At 5735'-573T ~~~~~ 12 Shots 8 Shots Per Ft. POOH Lay Down Equip. RIg Down RIG_ FR1CSG Rig Up To Run Seal Asst'. In Hole.. DP_ PR1 CSG RIH W/Tie Back Seal Asst'. F/Cmt. Squeeze At 5735` CMT_ PR1CSG PJSM; R/U Baker Cmt Head. Asst'. CMT. PR1 CSG PJSM; Circ At 4585'. Out Of Liner 3bbis min.= 600psi 4bblsmin = 945psi. Stab Into Liner W/Tie Back Seal Asst'.. Circ At 4 bbl min=1050psi /Batch Mix 43bbls 13ppg-Lead And 10bbls 15.8ppg Cement. CMT_ PR1CSG Pump 2 bbl H2o, Test lines To 4500psi Pump 43bbls. 120sx 13ppg Lead Class G + 10% BA-90 +2.5%BA-90 5% EC-1 + 5%SMS +4% CD-32 = .1 % ASA-301 + .05 Static Free + 1 gps FP-6L. Yield 2.01. Pump 10 bbls 50 sx 15.8ppg Class G Neat Cement W/ Yield Of 1:15 4.93 gps Total of IObbls/50 sx Pumped. 100% Returns Note Spacer Not :Pumped Due To No Mcs4 Spacer In Bulk Tank.10bbls Of Iead Was pumped Without Additives.BJ Failed To Blend At Bulk Plant. Displace W/ 37.9bb1 13.5ppg Mud: Cement in Place At 0749hrs. 100 % Retums Max. Squeeze psi 1645 GMT_ PRICSG. Un Sting F- Liner Top And Reverse Out 22bbis mud Followed By 7.tbbls Cement. Circ 2x Drilistring Volumes Shut Down Circ Long Way Clean Up Liner Top At 4590' No Cement Returned ,Liner Top Cleaned Up. OTHR PRICSG R/D Bot CementHead DP_ PRI GSG POOH F- 4590 W/Tie Back Seal Asst' Printed.;. 11/28/2007 723:18 AM ~ ~ Marathon: OiI Company Page 3 of 5 Operations Summary Report Legal Well Name:: SUSAN DIONNE 5 Common Well Name: SUSAN DIONNE 5 Spud Date: 7/13/2006 Event Name:. ORIGINAL COMPLETION Start: 8/5(2006 End: 8/16/2006 Contractor Name: GLACIER DRILLING: Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date Erom - To Hours ...Code Code Phase Description of Operations 8/9/2006 13:30 - 19:30 6.00 TEST_ BODE PRICSG PJSM; Test BOPS And All Related Components 250!3000 Witness Waved By Chuck Schevie AOGGG 19:30 - 00::00 4.50 TRIP_ DP_„_ PRICSG MN BOT 5.25" Polish Mill Assy RIH To 4550' Wash And Clean Out To 4590' 00:40. - 01 s00 1.00 CLNOU CSG_ PR1CSG Clean Out Liner Top At 4590' Polish Tie Back Sleeve To 4596'. Entry Into Sleeve Slick. Rotate 10 rpm Max'fq 2400 Circ 8/U. 01:00 - 01;30 0.50 RURD_ OTHR PR1CSG R/U To UD 2 7/8 Qrillpipe, Pump Dry Job 01:30 - 06:00 4.50 fiRiP_ DP_ PR1 CSG POOH. F 4590' L1D 2 718 Drillpipe To 400' 8/10/2006 06:00 - OZ:00 1.00 TRIP_ DP_ PR1GSG Continue UD Drillpipe Stand back Drill Collars UD polish. Mill 07:00 - 07:30 0.50 PULD PKR PRICSG PJSM; P/U Baker 2XP Packer & M/U 07:30 - 08:;30 1.00 _ TRIP DP_ PRICSG PN 4 °HWDP RIH 08:30 - 09:00 0.50 REPAIR RIG_ PR1 CSG Repalce HT-38 Savor Sub On Top Drive 09:00- 13:00 4.00 TRIP DP_ PR1GSG RtH IN/ZXP Packerdn 4" Drillpipe 13:00 - 15::00 2.00 SETREL PKR_ PR1 CSG Up wt.80K Dn Wt. 45K Tag Liner Top At 4590' Sting In ,Set 25K Down,Drop Bali Hook Up Mud lines, Pressure Up TO 2200 PSI,SetZXP Packer Pressure To 3700 Psi To Release Tool ,Pressure to 4000PSI To Blow Ball Seat,Packer Top At 4563' 15:00 -17;00 2.00 TRIP_ DP_ PR1C5G PJSM;POOH W/ 4" Drill Pipe 17:00 - 18:00 1.00 TRIP BHA_ PRICSG Lay Down HWDP And Running Tool 18:00 - 18:30 0.50 CLEAN_ RIG_ PR1CSG Clear Rig Floor And Rig Up Weatherford to Run 2 7/8 Drill Pipe 18:30 - 02:30 8.00 `TRIP DP_ PRICSG PSSM;RIH With Motor, Mill, And Drill Pipe To 4550' Drift And Strap 2 7/$ D/P 02:30 - 03:30 1.00 TEST_ CSG_ PRICSG Break Circ. Close Pipe Rams And Test Liner PackerAnd Gsg. To 800 PSI For 30 Min:. Test Good 03:30 -04:00 0.50 TR1P_ DP_ PR1CSG Cont. Running In Hole F- 4550 ' T-5139' 04'00 - 04c30 0.50 RURD OTHR PR1CSG R/D Power Tongs For 2 7/8 Drillpipe C/O To 4" Drillpipe 04:30 - 05:00 0.50 _ TRIP. DP_ PR1CSG Cont. RIH W/ 4" Drillpipe To 5535' Tag Cement Stringers. 8/11/2006 05:00 - 06:00 06:00 - 08:00 08:00 - 09:00 09:00 - 11:00 1.00 2.00 1.00 2.00 DRILL_ DRILL CIRC_ TEST_ CMT_ CMT_ MUD_ CMT_ PR1CSG PRICSG PRICSG PR1 CSG Drill Cement Stringers F- 5535' Tag Firm Cement At 5575' Drill Cement F- 5575' To 5600' Drill Firm Cement F- 5600'- 5745' Circulate Bottoms Up At 5745' Test Sgu_eezed Perfs At 5735'-5737` T/800 PSl bled. back o 675 PSI 11:00 -11:30 0.50 DRILL_ CMT_ PR1CSG Drill Out Cement-Bridge Plug F/5745'-5752' 11:30.- 1.3`.00 1.50 TRIP_ DP_ PR1CSG RIH To 6080' Lay Down One Bad Joint 4" DP And Replace 13:00-1.6:30 3.50 TRIP:. DP_ PRICSG Continue RIH F/6080'-9423' 16:30 - 18:30 2.00 DRILL_ CMT PRICSG Wash F/9423'-Tag Up Cement At 9431' Clean Out Cement F/9431'To Landing Collar At 9469' Up Wt.170K Dn Wt.70K 18:30 = 20:30 2.00 CIRC_ MUD_ PR1 CSG Drop 7!8 Steel Ball To ShearCirc. Sub Monitor Well, :Pump Dry Job,Fll Trip Tank 20:30 - 23:00 2.50 TRIP_ DP_ PRICSG PJSM;POOH With 4" Drill Pipe for BHA Change 23:00 - 00:00 1.00 RURD_ RIG_ PR1 CSG. PJSM;Rig Up To Pull 2 7/8 DriA Pipe 00:00 - 03:00 3.00 TRIP DP_ PR1 CSG POOH W/ 2 718 Drill Pipe 03:00 - 05:00 2.00 TRIP_ BHA_ PR1CSG POOH WI BHA Measure And Ptck<up Bit And 4 1/2".And T' Scrapers In Tandem 05:00 - 06:00 1.00 TRIP_ DP_ PRICSG RIH W/ 4112 Scraper On 2 7/8 Drillpipe 8/12/2.006 06:00 - 08:00. 2.00 TRIP_ DP_ PR1CSG Cont. RIH F-1250' - 5000' 08:00 - 08:30 0.50 RURD/ DTHR PRICSG R/D 2 7/8 Drillpipe Handling Tools! R/U 4" Drillpipe Tools 08:30 - 09:00 0.50 TRfP DP_ PRICSG P/U 7" Csg. Scraper 09:00 - 10:00 1.00 CUT_ .WIRE PR1GSG PJSM;SIip Drilling Line 33' /Service Rig 90:00 - 12:30 2.50 TRIP DP_ PRICSG Cont. TIH F- 5000' T- 9468' .12:30 - 14130 2.00 CIRC. MUD_ PR1CSG Circ, Pump Sweep C/O Well Bore At 94Ei8' Circ At 114spm 1975psi 145gpm Returns 11f28/2007 7:23:48 AM ~ ~ Marathon. Oil Company Page ~ of 5 Operations Summary Report.. Legal Wel! Name: SUSAN DIONNE 5 Common Well Name: SUSAN DIONNE S Spud Date: 7/1312006 Event Name: ORIGINAL COMPLETION Start: 8_/5/2006 End: 8/16/2006 Contractor Name::: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To Hours Code ode Phase Description of Operations 8(12/2006 12:30 - ~ 4:30 2.00 CIRC MUD_ PRICSG Over Shakers Fine Sand! CementAnd Rubber From Plug. Shakers Cleand Up With 3x B/U 14:30-16:00 1.50 CLEAN_ TANK PRICSG Clean Pill Pit, Flush Lines Prep For KCL Displacement 16:00 - 18:00 2.00 CIRC_ CFLD PR1CSG Circ. Pump 8.6ppg KCL Sweep/ spacer W Flow Vis And E/P Lube. Followed By 212bbis 8.6KCL Brine: W/ Congor A303. Displace 9.6 Flow Pro Mud To Hanson Tank. Cire Untill Clean Brine Returns. 18:00 - 18:30 0.50 TEST CSG_ PRICSG Test 4 112 Csg. 800psi / 765 Final psi 18:30 - 23:00 4.50 TRIP_ QP PR1CSG PJSM; POOH Up 4" Drillpipe 151jts 4691' Total 23:00. - OOa)0 1.00 RURD OTHR PRICSG R/D 4" Drillpipe Handling Tools. R/U 2 T/8 D,P. Handling Tools 00:00 - 05.;00 5.00 TRIP_ DP PRICSG PJSM; POOH UD 2 7/8 Drillpipe 161 Jts. 5001' Lay Down Drill Collars BHA 05:00 - 06:00 1.00 CLEAN_ RIG_ PR1TIE Clean Rig Floor. UD 2 T/8 Drillpipe Subs Elevators And Tools. Load Out SI13/200ti 06:00 - 09:00 3.00 RUNPU TBG_ PRITIE PJSM; R/U To Run 4 1/2 Completion. Clear Rig Floor Of All 4 "Drillpipe Handling Tools. CIO Elevators, Bails. RLU Tubing Tongs. 09:00 -10:00 1.00 RUNPU TBG PRITIE n Strin . M/U Baker Seal 10:00- 1.3:30 3.50 REPAIR RIG_ PRITIE 13:30 -19:00 5.50 RUNPU TBG_ PRITIE 19:00-20:00 ~ 1.00 PULD_~TBG_ PRITIE 20:00 - 21;00 ~ 1.00 ~ TEST_ ~ WLHD ~ PRITIE 21:00 - 23:30 ~ 2..50 ~ CLEAN_ RlG_ ~ PRITIE 23:30 - 06:00 ~ 6.50 ~ NUND ~ BOPE ~ PRITIE 8/14/2006 06:00 - 07:00 ~ 1.00 TEST_ +TREE PRITIE - 06:00 ~ 23.00 ~ RURD_~ RIG_ ~ RDMO ~ 8/15/2t)06 ~ 06:00 - 06;00 ~ 24.00 (RURD_~ RIG_ ~ RDMO Assy. Followed By 4 1 /2 ibt I-80 12.60 Tubing Repair Rig. Extend Arm, Drillers side On Top Drive Sheard Off. Remove And Repair Same. Repair Hyd. Fitting on Actuator For'Hyd Safety Valve, Top Drive Broken-Off During Repair Of Extend Arm) Cont Rih W/ 4 1/2 Tubing F- 500' - 2200' Install Baker Chem Injection Nipple Setting Depth 2385'. Cont. RIH W / 41/2 Tubing F-2200' T-4545 Space Out And Make Up Tubing Hanger Up Wt60K Dn Wt.40K Top Of Liner At 4569' Bottom Of Seals At 4580' Chemical Injection Mandrel At 2385' Test Well Head Body And Tubing. Hanger Seals To 5000 PSI F-10 Min. Test Tubing And Liner Top To 800 PSI 30 Min. Test Good Flush Surface Equip. With Fresh. Water,Lay Down Weatherford Equip:. Clear Floor. Clean Pits PJSM;Set Backpressure Valve Nipple Down BOP Instal{ Production Tree. Clean. Pits Test Void to 5000 psi / 10 min. Pull BPV Set TWC. Test Tree To 5000psi/10min All Test Good. Install. BPV Commence RlD. Prep For Move. Pull Wires To Gen. House.. Remove:#3 Mud Pump. R/D:Pits. R/D Mech/ Parts House. Remove #1 Pump Motor, Set Replacement Motor In Place, C/O Pump Liners To 5" RID Service Lines To Top Drive.. UD Top Dnve. PJSM;: R/D Torque Tube RID Derrick Board, R/D Mud lines, Scope Down. Mast, R!D Dog and Choke Houses, Load Out Epoch, Cuttings And Hanson Tank. Crane Down Windwalls Dog And Choke House. Lay Mast Down,. Remove Board. Remove Stairs And Landings. Load Out Pump #3 House. Complete Crane Work.. Remove Heaver Slide. Cat Walk And Load Out. M/O Trip Tank. Load Out All Windwalls Dog And Choke House. Printed: 11/18I20R7 7:23148 AM Marathon Oil Company Page 5 of'5 Operations Summary .Report Legal Well. Name: SUSAN DIONNE 5 Common Well Name: SUSAN DIONNE 5 Spud Date; 7/13(2406 Event Name: ORIGINAL COMPLETION Start: 8/5/2006 End: 8/16/2006 Contractor Name; GLACIER. DRILLING Rig Release::. Group: Rig Name: GLACIER. DRILLING Rig Number: 1 Date -From - To Hours Code Cotle Phase Description of Operations 8116/2006 06:00 - 12.00 6.00 RURD_ RIG_ RDMO Split Pits,Pump Room,Rig Dawn Gen.,Boler Houses.Pull EleckWires,Load Out Carrier Mud Boat,Move Sub Off Well And. LowerAnd Prep For Road. Release Rig To Clu -12 42:00 firs 6-15-06 Pdntnd~ 1U7AF90~7 7.934A Marathon +~il Company Page 1 of s Operations Summary Report Legal Well Name: SUSAN DIONNE 5 Common Well Name: SUSAN DIONNE 5 Spud Date: 7/13/2046 Event Name: ORIGINAL COMPLETION Start: 8/25/2006 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To Hours Cotle Code phase 8/25/2006 07:30 - 08:30 1..00 WORK. ELEC MIRU 08:30 - 09:25 0.92 WORK ELEC WRLN 09:25 -10:30 1.08 WORK. . ELEC WRLN 10:30 -.12:30 2.00 WORK. ELEC WRLN 12:30 -13:10 0.67 WORK. .ELEC WRLN 13:10.-13:40 0.50 WORK. ELEC. WRLN. 1.3:40-1&:30 2.83 WORK :ELEC WRLN 16:30 - 1?:30 1.00 RURD_ ELEC RDMO 9/15/2006 07:00 - 08:30 1.50 08:30 - 9 7:30 9,00 9/16/2006 07:00 - 08:30 1..50 RURD COIL CTBG 08:30 - 09:30 1.00 WORK COIL CTBG 09:30 - 09:40 0.17 WORK . COIL CTBG 09;40 - 11:25 1.75 WORK COIL CTBG 1.1:25 -12:10 0.75 WORK . COIL CTBG 12:10 - 12:45 0.58 WORK COIL CTBG 12:45 - 13:24 0.65 WORK. COIL CTBG. 13:24 - 13:55 0.52. WORK COIL CTBG 13:55 - 14:05 0.17 WORK COIL. CTBG 14:05-1.5:00 0.92 WORK COIL CTBG 1:5:00 - 16:15 1.25 WORK COIL. :CTBG Description of Operations ` MIRU wire line. unit, held PJSM and discussdd operation, discussed potential hazardus and safety issues around well head.. RIH with 1 11/16", CCL, stem, spang jars, 3.75" GR and junk basket, Sat down at 2800' KBD, tried to work tool string through. Tools would not fall through. POOH OOH with tool string. Add additional stem to tool string. RIH with GR to 9470` KBD OOH with GR, hand full of hard plastic in junk basket MU slim line logging tools. RIH could not get below 1500' KBD, POOH. MU tool: string with additional $` stem. RIH with tool string, work tools pastthe 2800' KBD, made lopping pass at top of cement from 6900' - 7100' KBD, continue down. hole. Sat down at 9470'.., made up pass to 9000' KBD for repeat log. Drop down hole.. PUH logging at 30/35 FPM. Logged through 4500' I<BD. POOH with tool string. OOH with logging tools, lay down lubricator RD Unit MIRU.. coil unit. Held PJSM and discussed well operations.. Upatained work permit and discussed JSA on rig up. Continue stagging equipment for rig up and coil hook up. RU flow back .iron to gas buster, choke and open'top tank, Pulled fresh water from well and competed BOPS test on BOP's. Low pressure test 200 psig, .high 3500 psig. Test good. Rig back coil for tomorrow reverse oirculate fluid. BJ.left lease. BJ Coil tech on location, held PJSM, discussed safey issues and crane operations. Uptained work permit and dscussed operation with production. PU injector take to well. Shell test o 3000 psig art back side'iron, OK. Pump remaining water from pumps. to blow down tank. Total 21 bbls in flow back tank at start of job. RIH with 1 3/4" coil, Pump N2 at min rates of 500 SGFM Casing pressure at 962 psig,. CT @ 2215' CTM. Coil. at 6700', park coil,. increase N2 to 1200 SCFM. 3/4 BPM filuid to .tank, Good returns to flow back tank, total 103 bbls fluid.. to tank. PIP= 2225 psig, WHP= 99 psig, N2 cut bade. to 750 SCFM. returns at 3l4 BPM RIH to 7425' CTM, increased N2 at 1200 SCFM, 133 bbls to F/B tank, 85 bbis from well.; Casing pressure at 2250 psig, WHP= 85 psig Cut N2 back to 500 SCFM, RIH to 8150' CTM. increase N2 to 1200: SCFM. WHP= 290 psig,: Casing pressure at 2154 psig. N2 total at 147, 000 SCF. Csg pressure at 2250 psig, cut N2 back to 500 SCFM, fluid to tank. 'RIH with tail to 8875' CTM. Total fluid to tank = 166 bbls total, 118 bbls from well. Increase N2 to 1.200 SCFM Pressure increased to 2250 psig, cut N2 back to 500 scfm. RIH with coil tagged up at 9456' CTM, PUH with coil, parked coil increased: N2 rate up to 1:200 SCFM. Casing pressure= 2200 psig, WHP= 0 psig, total N2 pumped = 203, 149 SCF. Pumped N2 for 50 minutes no change in WHP. Suspect plugged nozzle, Shut in N2, no change in WHP= 0 psig. POOH with. coil.. Coil at 4400' CTM, N2 to fiow'back tank, some fluid, nozzle un plugged. Stop coil, RIH with coil #0 9400' CTM. Park coil, N2 rate up to 1200 PrlntBtl: 11r1t3/Ltill!' /:'L3a5/ AM • Marathon ail Company Operations Summary Report Legal Well Name:. SUSAN DIONNE 5 Comman We(I Name: SUSAN DIONNE 5 Event Name: ORIGINAL :COMPLETION Start`. 8/25/2006 Contractor Name: GLACIER DRILLING Rig Release: Rig. Name: GLACIER DRILLING Rig Number: 1 Page 2 of 8 Spud Date: 7/13/2006 End:: Group: Date From - To Hours Code Code. . -Phase Description of Operations 9/16/2006 15:00 - 16:15 1.25 WORK COIL CTBG SCFM. Total fluid to tank = 186 BBLS, 138 BBLS from welh Total N2 224, 935 SCF: 16:15 - 1.7:40 1.42 WORK COIL CTBG Work pressure on Casing back to 2350 psig, no returns to tank. Total. N2 pumped = 265, 250 SCF. WHP up to 2413 psig 17140 - 19:00 1.33 WORK. COIL.. . CTBG POOH with coil, Coil at 4000', returns to tank, 314 BBL fluid to tank. with N2, continue OOH with coil to inspect the nozzle. Choke shut in. 19:00- 20:00. 1.00 WORK . COIL CTBG Blow down coil to flow backtank. Total fluid in tank= 191 BBLS,. total fluid from well 142 BBLS,'fluid level calculated at 9350', 60' below planned perforations. at 9290'. Racked up injector, put night capon well head. Pump N2 to leave 2000 pslg on wolf. 20:00 - 21:00 1.00 RURD_ COIL. CTBG RD ROPE and coil. BJ left lease. 10/312006 07:30 - 08:00 0.50 SAFETY . MTG_ CMPPRF Discussed Expro JSA and safety checklist. Assigned duties for jobs. 08:00 - 09:30 1.50 RURD_ ELEC CMPPRF RU expro. 09:30 - 09;45 0.25 SAFETY MTG_ CMPPRF Perforating safety meeting. 09:45'-10:15 0.50 RURD ELEC CMPPRF Arm Gun #1.26', 3-3113" 6spf. 60 deg. 0.36" entry hole,.: 40" penetration. . 10:15 - 11:45 1.50 RUNPU - ELEC CMPPRF RIH Gun #1. Tie into CBL. Tag TD at 9440' ELMD. 11:45 - 12:10 0.42 RUNPU ELEC CMPPRF Position gun. 5' CCL to top shot. 9258' to shoot 9263' - 9289'. SIWHP' 12:10 -12:15 0.08 PERF~ C5G_ CMPPRF Shoot gun#land perforate 9263' - 9289' and log off. 12:15 -13:00 0.75 RUNPU ELEC CMPPRF OOH.. P= 1675 psi:. 13:00 - 13:35 0.58 RURD_ ELEG CMPPRF LD spent gun and PU Gun #2, 16', same as gun #1. P=1700 psi 13:35 -14:45 1.17 RUNPU ELEC CMPPRF RIH gun #2 14:45 - 14:55 0.17 RUNPU ELEC CMPPRF Tie in to CBL. P =1755 14:55 -15:05 0.17 PERT CSG_ CMPPRF S t Gun #2 n erforate 8508' - 8524' CBL and log off. Gun stuck. ~ for 1 minute. 15:05 - 15:50 0.75 RUNPU ELEC CMPPRF POH 15:50 -1.6:25 0.58 RURD_ ELEC CMPPRF LD spent gun and PU Gun #3, 6' same as #1. - 16:25 - 17`.50 1.42 RUNPU ELEC CMPPRF RIH Gun #3, P - 1855psi. at 1750 PM 17;50 -17:55 0.08 PERF` CSG_ CMPPRF Tie in to CBL. Shoot 8270' - 8276' CBL. No strong response. 17:55 -18:30 0.58 RUNPU ELEC CMPPRF POH. 18:30 -.19:00 0.50 RURD_ ELEC CMPPRF Rig back for night. Bleed well from 1875 psi to 1375 psi and observe pressure buildup. 10/4/2006 07:30 - 08:15 0.75 SAFETY MTG_ CMPPRF Discussed Expro JSA and safety checklist. Assigned duties for jobs.. 08;1.5 - 09:30 1.25 RURD^, ELEC CMPPRF RU expro. PU SRO PFT tools. Shut in pressure =1830. psi 09:30 -1:0:20 0.83 RUNPU ELEG CMPPRF Attempt o RIH PlT. Unable to RIH. POH 10:20 -10:30 0.17 RURD_ ELEC CMPPRF Add 3-118" weight bar to tool Mng. 10:30 -12:15. 1..75 RUNPU ELEG CMPPRF RiH to fluid level at 5850' ELMD CBL Squeeze profs appear to be talon some as. 12:15 - 13;20 1.08 LOG_ CSG_ CMPPRF Lag P/Tstatic pass from 8000"- 9350'. No indication of perfs. 13:20 - 14;05. 0.75 BLOWD BG_ CMPPRF Blnw down well from 1.810 psi to 1300 psi. 14:05 - 14:45 0.67 LOG CSG CMPPRF Log PR from :9350' - 8000', Well appears to be making a small amount. ..c „ate i...n..:Q~ns2 _ftf,:]A :ntcn,~l~nrV ,ar~far frnm R~7n"., A77R' intarvaT- 14:45 - 15:10 0.42 LOGT CSG_ CMPPRF Log PIT from 8000' fo 9350'. Pass confirms water entry from up pass:. 15:10 - 15:55 0.75 RUNPU. ELEC CMPPRF POH. Fluid level at 5100'.. 15:55 - 16:40 0.75 RUNPU ELEC CMPPRF POH 16:40-17:45 1.08 RURD_ ELEC CMPPRF RD and release Expro. 10/12!2006 07:30 - 08:05 0.58 SAFETY MTG_ CMPPRF Discussed Expro JSA and safety checklist: Assigned duties for jobs. 08:05 - 09:05 1.00 RURD_ ELEC CMPPRF RU expro. PU SRO P/T tools. PU 3 roller bogies and 2 weight. bats. Shut in pressure = 1520 psi 09:05 - 11:20 2.25 RUNPU ELEC CMPPRF RIH to fluid level at `ELMD CBL. Squeeze. profs. appear to be taking. some gas. 11:20 - 12:55 1.58 LOG_ CSG_ CMPPRF Log PIT static pass from 4700' - 9350'. POH to 4700`. 12:55 - 13:57 1.D3 BLOWD BG CMPPRF Blow down well from 1520 psi to 0 psi. Fluid reached. tools in 10 PtinCed: '11/28/2007 723:57 AM • Marathon Oil company Page 3 of 8 Operiations Summary Report Legal Well .Name;: SUSAN DIONNE 5 Common Well Name' SUSAN DIONNE 5 Spud Date: 7/13/2006 Event Name:. ORIGINAL COMPLETION Start: 8/25/2006 End: Contractor Name:. GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To Hours Code Code Phase Qescription of Operations 10/1.2/2006 12:55 - 13:57 1.03 BLOWD BG~ CMPPRF minutes, 2 bbls flow at 300 psi drawdown in 10 minutes St well when water started flowing to tank. 13:57 -15:05 1.13 `LOG_ CSG_ CMPPRF Log P/T from 4700" - 9350'. Well apRears to be making water from 15:05 -:15:50 0.75 RUNPU ELEC CMPPRF POH to 5000'. Observe well 10 min. 15:50 -17:05 1.25 LOG_ CSG_ CMPPRF Lag P/T from 5000' to 9350'. Pass confirms. 1.7:05 - 18:00 0.92 RUNPU ELEC CMPPRF POH. Fluid level at 950'. 18:00 -18:45 0.75 RURD_ ELEC CMPPRF RD and release Expro. 10/17/2006 09:00 - 09:40 0.67 SAFETY MTG_ CMPPRF Discussed Expro JSA and safety checklist:. Assigned duties for jobs. 09:40 - 12c20 2.67 RURD €LEG CMPPRF RU expro. PU lubricator and tool string. Patch is missing one Collette. 12:2Q -:13:00 0.67 RUNPU ELEC CMPPRF Rig. back equipment until patch collete arr'nves (noon#omorrow), 10/18/2006 11:30 - 12:00 0.50 SAFETY MTG_ CMPPRF Discussed Expro JSA and safety checklist. Assigned duties for jobs., 12:00 -1.3:30 1.50 RURD_ ELEC CMPPRF RU expro. PU lubricatorand toot string. 13:30 -13:45 0.25 SAFETY MTG_ CMPPRF Hold explosive safety meeting. Complete perforating check list. start radio silence. 13:45 -14:00 0.25 RURD_ ELEC CMPPRF Arm patch setting tool and RIH to :200'. 14:00 - 15c05 1.08 RUNPU ELEC CMPPRF Finish radio silence. RIH patch #1. 15:05 - 16;00 0.92 RUNPU ELEC CMPPRF Tagged PAC tool (stage cementer). Stuck in PAC. Flowed well and worked free. Attempted, to pass PAC. Unable to get through. 16:00 - 17;1:5 1.25 RUNPU ELEC CMPPRF POH. 16:45 - 17:15` 0.50 RUNPU ELEC CMPPRF Start radio silence 17:15 - 18:00 0.75 RURD_ ELEC CMPPRF Rig down Expro eline. Patch had metal gouging an sides ctoseto bottom and some gouges several feet up. 10/20/2006 08:00- 08:30 0.50 SAFETY MTG_ PATCH Safety Meeting,. Pollard JSA,, Slips Trips Palls, Crane Safety, MIRU with Expro Equipment still on site. Make sure that equipment is properly flagged off. 08:30 - 10;30 2.00 RURD_ SLIK PATCH RU Pollard W/L, Pressure Test Lubricator, test ak 10:30 - 10:50 0.33 RUNPU SLIK PATCH R1H w! 3.80" Gauge Ring, Set down @ 1250' WLM 10:50 -11.:20 0.50 RUNPU SLIK PATCH Pick Heavy, PpOH real slow, 1250 Ibs Cverpull, OIaH 11:20 - 12:30 1.17 FLOW TEST PATCH . Flow well to remove heavy grease. @ 1250' WLM,. Flowed 12 obis from 12:30 - 14:00 1.50 RUNPU SLIK PATCH 14:00 - 15:40 1.67 RUNPU SLIK PATCH 15:40- 15:50 0.17 RUNPU SLIK PATCH 15:50-76;10 0:33 RUNPU SLIK PATCH 16:10 - 17:00 0.83 RUNPU .SLIK :PATCH `17:00 -113:00 1.00 RUNPU SLIK PATCH 18:00 - 18:30 0.50 .RURD_ SLIK PATCH 10/24/2006 08:30 - 09:30 1.00 SAFETY MTG_ PATCH 09:30 -10:1.5 0.75 RURD_ SLIK :PATCH 10:15 - 11:30 1.25 RUNPU SLIK .PATCH 11:30 - 12;30 1.00 RUNPU SLIK PATCH Added stem, RIH wl 3.80" GR to 3170' WLM, tools slowed down and'. crawled to 3600' WLM, no improvement (possible pushing stuff dawnhole) POOH, Heavy pull (150Q-1700 Ib overpull), flowed w~l to assistin POOH:. Flowing well had little effect on assisting tool string out of hole, 2850° WLM wire drag weight was lost and. pull out of the hale free. OOH, check GR, coated w/grease (na scratches or dents on GR) RIH w/ same to 1850' WLM, set down, POOH, Flow well RIH w/ same to 4615' WLM, sat down, POOH and puled free at 3870' WLM Gauge ring ok, RIH w/ same to 4590` WLM. slowed down and continued to 4606' WLM, stops, POOH, wire drag weight was losfat 3630' WLM DOH., Lay down lubricator, secure well and wmplete paperwork and sign out Safety Meeting, Pollard JSA, Slips Trips Falls, Crane Safety, MIRU with Expro Equipment still on site. Make sure that equipment is properly flagged off. RU Pollard W/L, Pressure Test Lubricator, test ok RIH w! 3" DD Bailer to 8400' KB, POOH (bleed off produced water from lubricator) RIH w/ 3.54" GR to 8400' KB, POOH (bleed off water) 7:23:57 AM Legal Well Name: SUSAN DIONNE 5 Common Weii Name: SUSAN DIONNE 5 Event Name: ORIGINAL COMPLETION Contractor Name: GLACIER DRILLING Rig Name: GLACIER DRILLING Date From - To Hours Code Code Phase 10/24!2006 12:30 - 13:30 1.00 RUNPU SLIK PATCH 13:30-14:15 0.75 RUNPU SLIK. PATCH 14:1.5 -16:15 ( 2.00 RUNPULJ SLIK.: ~ PATCH 16:15 - 17:00 l 0.751 RUNPULI SLIK. ~ PATCH 17:00 - 18:30 1.50 RUNPU. SLIK PATCH 18;30 - 19:00 0.50 RURD` SLIK PATCH 10!25/2006 07:30 - 08:00 0.50. SAFETY MTG_ PATCH 08:00 - 09:00 1:00 RURD SLIK PATCH 09:00 - 11:30 2.50 RUNPU SLIK .PATCH 11:30 - '13:00 1.50 RUNPU SLIK PATCH 13:00 - 73:30 0.50 RURD SLIK PATCH 13:30 - 16:00 2.50' RUNPU SLIK PATCH 16:00 - 17:30 1.50 RURD SLIK PATCH 17:30 - 18:00 0.50 RURD_ ELEC PATCH 18:00:- 18:20 0.33 RURD. ELEC PATCH 18:20 - 18:48 0.47 RUNPU ELEC PATCH 18:48 - 19:29 0.68 RUNPU ELEC PATCH 19:29 - 20:20 0.85 RUNPU ELEC PATCH 20:20 - 21;00 0.67 RURD_ ELEC PATCH 10/26!2006 08:30 - 09::15 0.75 SAFETY MTG_ 'PATCH 09:15 - 11:00 ~ 1.75 ~ RURD_ SLIK ~ PATCH 11:00 -11:30 ~ 0.50 ~ SAFETY ~ MTG_ C PATCH 11:30 - 15:30 4.00 RURD_ SLIK PATCH 15:30 - 17:45 2.25 RUNPU BRDL PATCH 17:45 - 19:00 1.25 RUNPU BRDL PATCH 19:00.-20:00 1.00 RURD_ SLIK PATCH 10/27/2006 D7:30 - 08:00 0.50 SAFETY MTG_ PATCH. Marathon-Oil Company Operations Summary Report Page 4 of 8: Spud Date: 7/13/2006 Start: $/25/20D6 End; Rig Release: Group: Rig Number; 1 bescription'of Operations RIH w/ 3,60" GR to 8400' KB, POOH (bleed off water} RIH w/ 3.75" GR to 4585' KB, work tool, pull up tp 400Q' KB, run at tight spot, fell through,continue to 8400' KB POOH, (bleed off water) RIH w/ 3.80" GR to 4585' KB, work tool, pull up to 4000' KB, run at tight spot, fell through, continue to 6989' KB, set down, work tool through and continue to 8400' KB. POOH and hung up at6989' KB, Pulled through w/ 1 oil jai' lick @ 1400# overpull, work toots through tight spot... POOH, change tools RIH w/ 3.83" swedge to 1650' KB, would notpass (NOTE: Drift is smaller than 3.83", Possible overtightened couplings, when POOH swedge located every tubing joint.) POOH RIH w/ 3..80" GR, se# down. at 4585' KB, worked tool past, fell: thru, continue to 6989' KB, work tools (work up and down mulfiple times, POOH (obstruction was lessened during this run) Almost full 3.80" drift #hru PAC tool. and ZXP. Rig down wireline for the night, sign out and leave lease Safety Meeting, .Pollard JSA, 5tips Trips Falls, Crane Safety, MIRU with Expro Equipment till on site. Make sure that equipment is properly flagged off. RU Pollard W/L, Pressure Test Lubricator, test ok RIH w/ 3.82" gauge cutter. Worked down through PAC tool at 6989'. Beat down and up through PAC tool until 3.82" drift will passe easily. POH. 'RIH w/ 11' X'3.80" dummy patch. Unable. to get deeper than 2665' POH. PU extra section lubricator and extra 5' of 1.75" weight bar: R1H w/ 11' X 3.80" dummy patch: Passed through PAC tool to 7400'.. POH dummy LD tools and lubricator. RD crane. RU Expro eline unit. Rrm patch. setting tool and stab on well. RIH 11.75' X 3.80" OD X 3.375" ID permanent patch. Position to cover Work wire and .pull out ofi weak point POH with no tools:. Rig down eline unit. Prepare to fish etting tool. Safety Meeting, Pollard JSA, Slips Trips Falls, Crane Safety,.. Expro Equipment Rigged down and on pad. Make sure thatequipment is properly flagged off. RD Pollard W/L and Spot Braided Line skid. and Grease Skid. Wait on Steve from pollard to come with correct pulling tools and for safety meeting with Pollard, Expro, ASRC Crane riper. and MOC. Hold. Safety Meeting with Pollard, Expro, ASRC, and MOC. Discuss job.: and personal. responsibilites. Expro assisted in providing extra lubricator (42' setting tool that needs to be fished) and Crane assistance. RU Braided line'The Hammer" and Lubricator (approx 80' of Lub) RIH w/ 1.25" JD Pulling Tool. to 8150' BLM, work tool, 2 Oil Jar Licks, and it pulled off each time.. POOH RIH w/ overshot baited w/ 2.31" external fishing neck looking up LD tools and lubricator. RD crane. Lay down for the might. Safety Meeting, Pollard JSA, Slips Trips Falls, Crane Safety, Expro Equipment Rigged down and on pad. Make sure that equipment is 11/28I2Q07 7:23:57 AM • Marathon Oi,f Company Page 5 of s Operati®nS Summary Report Legal Well Name: SUSAN DIONNE 5 Common Well Name: SUSAN DIONNE 5 Spud Date: 7/13/2006 Event Name: ORIGINAL COMPLETION Start: 8/25/2:006 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To Hours Code Code Phase Description of Operations 10/27/2006 07:30 - 08:00 0.50 SAFETY MTG_ PATCH properly flagged off'. 08:00 - 09:00 1.00 RURD SLIK PATCH RU the hammer and PU Pollard and Expro lubricator. ~'~ 09:00 - 12:30 3.50 _ RUNPU BRDL PATCH RIH w/ 3" JDC pulling tool to 8218' and latch patch running tool. Hit jars one time with 5000# overpull and tool came free. POH and LD tools. 12:30 - 13:30 1.00 RURD SLIK PATCH Rig down and release Pollard slickline. 13:30 -14:00 0.50 SAFETY MTG_ PATCH Hold Expro pre job safety+meeting. 14:00 - 15:15 1.25 RURD_ ELEC PATCH Spot and RU Expro cline. 15x'!5 - 16:10 0.92. RUNPU ELEC PATCH RIH CCI to log patch. Well is no Icnger capable of making water to the 16:10 - 17:00 0.83 RURD_ ELEC PATCH POH 17:00 -17:1:5 0.25 SAFETY MTG_ PATCH Hold explosives safety meeting and go on radio silence. 17:.15 - 18:15 1.00 RURD_ .ELEC PATCH PU second 3.80" X 11' casing patch.. '1.8:15 - 19:15 1.00 RUNPU. ELEC PATCH RIH patch #2. CCL failed at 4700' with intermittent short• 19:15 - 19:55 0.67 RUNPU ELEC PATCH POH to change CCL. 1:9:55 - 21:15 1.33 RURD . .ELEC PATCH Test and change CCL. 21:15 - 22:15 1.00' RUNPU ELEC PATCH RIH patch #2 again. CCL.failed of 4700' with intermittent short: 2211.5 - 23:05 0.83 RURD_ ELEC PATCH POH to switch cables.. 23:05 - 00:00 0.92 RUNPU ELEC PATCH Change to 5/16" cable. 00:00 - 00:30 0.50 RUNPU ELEC. PATCH RIH to 200` and CCL failed. POH and change weight bars. 00:30 - 01:45 1.25 RUNPU ELEC PATCH RIH 11.75' X 3.80" OD X 3.375" ID patch #2 and set at 5733' - 5744.75'. 01:45 - 02:30 0.75 RUNPU .ELEC PATCH POH 02:30 - 03:30 1.00 RURD_ ELEC PATCH OOH. RD and release Expro. 10/28/2006 D7:30 - 08:00 0.50 SAFETY MTG_, CMPFLW Safety Meeting, Covered complete BJ checklist, Slips Trips Falls, Crane Safety. 08:00 -12:30 4.50 RURD_ COIL CMPFLW Spot and rig up BJ coiled tubing. 12:30 - 13:00 0.50 RURD._ COIL CMPFLW Secure equipment for weekend. 10/31/2006 07:30 - 08:00 0.50 SAFETY MTG_ CMPFLW Safety Meeting, Covered complete BJ checklist, Slips Trips Falls, Crane Safety. 08:00 - 09:30 1.50 RURD_ COIL CMPFLW Start equipment and stab injector on well. 09:30 - 11:20 1.83 TEST_ ROPE CMPFLW FiII CT and perform full BOP test. Test blinds, pipes and lines and valves 250 psi ! 4500 psi. 11:20 -12:40 1.33 RUNPU COIL CMPFLW R1H CT. Start n2 at 400 SCF/min. Tank has 66 bbls starting volume. 12:40.13:20 0.67 RUNPU COIL CMPFLW CTD=3000'. 13:20 - 14:10 0.83 RUNPU COIL CMPFLW Increase N2 to 500 SCF/min. Lift well from 5600'. 85 bbis net: returns.. WHP = 200 - 400 psi.. 14:10 - 16:30 2.:33 RUNPU COIL CMPFLW Jncrease N2 to 750 and lift well from 6100'.: VUHP = 350 psi,. net returns = 95 BBIs 16:30 - 18.20 1,83 RUNPU COIL CMPFLW increase N2 to 1500. Increase flawing WHP and RIH lifting. 18:20 -19:30 1.17 RUNPU. COIL CMPFLW Out of N2. Final depth = 8900'. final teturne = 132 Bbls. WHP = 900 psi. POH CT and hold WHP 19:30.20:30 1.00 RURD_ COIL CMPFLW Out of hole. Rig back CTU for night. 11/8/2006 10:00 -11:00 1.00 SAFETY MTG.. SLICK Arrive on location, sign in. obtain permit, Safety Meeting, Covered complete Expro JSA, SAps Trips Falls, Crane Safety. 11:00 - 13:25 2.42 RURD_ SLIK SLICK Begin to rig. up to run MPLT 13:25 - 13:41 0.27 RUNPU SLIK SLICK Open swab valve, noticed ice plug at surface, cycled valve & bled well 200 psig and attempted again 13:41 - 13:46 0.08 RUNPU SLIK SLICK Opened, valve and waited 5 min.. 13:46 = 14c2U 0.57 RUNPU SLIK SLICK Start in hole w/gauges 14:20 - 14:25 0.08 RUNPU SLIK SLICK Ran to 5000'.@.120'/min (stopped at 5000' for 5 min) 14:25 - 14:48 0.38 RUNPU SLIK SLICK Start run to T:D. @ 60'/min 1.4:48 - 14:53 0.08 RUNPU SLIK SUCK Tagged bottom @ 9325' SLM 1.4:53 - 16:20 1.45 RUNPU SLIK SUCK Pull up pass @ 60'Imin to 5000' SLM w/ 3 min stops at 9300', 927T, Pdnfed: 11128/2007 7:23:57AM ~ ~ Marathon Oil Company Operations Surnr~ary Roport Legal Well Name: SUSAN DIONNE 5 Common WeN Name: SUSAN DJONNE 5 Event Name: ORIGINAL COMPLETION Contractor Name: GLACIER DRILLING Rig Name: GLACIER DRILLING I Date From - To Hours Code Code Fhase 1118/2006 14:53 - 16:20 1.45 RUNPU SLIK SLICK 16:20 - 17:15 0.92 RUNPU SLIK SLICK 17:15 - 17:30 0.25 RUNPU SLiK SLICK 17:30 - 18:30 ' 1.00 RURD_ SLIK SLICK 18:30 - 19:00 . 0.50 RURD_ SLIK SLICK 2/23/2007 07:00 - 08:00 1.00 SAFETY MTG MIRU 08:00- 12:00 I 4.OO RURD (COIL (MIRU `12:00 - 13:30 1.50 RURD COIL .MIRU 13:30 - 15:45 2.25 TEST BOPE MIRU 15:45 - 16:30 0.75 RURD_ COIL MIRU Z/24/2007 ~ 07:00 - 08:00 1.00 SAFETY MTG CTBG 08:00 - 10:00 2.00 RURD COIL CTBG 10:00 - 11:00 1.00 TEST BOPE CTBG 11:00 - 11:30 0.50 WORK COIL CTBG 11:30 - 11140 0.17 WORK COIL CTBG 11:40 - 12150 1.17 JET..... N2_ CTBG 12:50 - 13`40 0.83 JET N2 CTBG 13:40 - 14:15 0.58 JET N2 GTBG 14:15 - 14:25 0.17 JET N2 CTBG 14:25 - 15:30: 1,0$ JET'_ N2~ CTBG r r 1:30 - 16:00 0.~0 JET_ N2, CTBG 16:00 - 16:05 0.08 JET N2 CTBG 16:05 - 16:25 D.33 JET_ N2_ CTBG 76:25 - 17:15 0.83 WORK COIL CTBG 17:15 - 17:20 0.08 SAFETY ~ MTG_ CTBG 17:20 - 17:45 0.42 RURD ~ COIL CTBG 17:45 - 18:20 0.58 RURD COIL 'CTBG 2/25/2007 ( 108:00 - 09:0 0 1.00 SAFETY MTG j WRLN , 09:00 - 09:30 ~ 0.50, RURD ~ _ ELEC ,WRLN 09:30 - 10:OU I 0.5.01 WQRK ELEC I WRLN Page 6 of 8 Spud Date: 7/13/2006 Start: $125/2006 End: Rig Release: Group: Rig Number: 1 Description of Operations 9200', 8519', $500', 7000', 5000' Start 120'lmin up pass at 5000' SLM (3 min stops @ 2500', 0') OOH. Wait 5 min and shut in well and verify data... RD equipment Sign out and leave location Held PJSM and discussed procedure for rigging up coif. Discussed working in extreme cold tempatures. Start equipment, lots of cold climate starting issues with crane and trucks. Spot equipment around well head. Ran hard line to N2 unit and BOP's. Made up all hard lines to choke and flow back tank. Load lines with 50/50 Methanol. PT hard lines and BOP'S low pressure @ 200 psig, high pressure @ 3000 psig. Good test. Stage N2 after test, get all equipment staged for running in well in the am. BJ crew left (ease. Start all equipment, uptain work permit, held PJSM and discussed operation for today. PU injector and go to well. MU Bowen connection. BHA 1.75" coil, wit connector, Bubble check valves, crossover and 2.25" nozzle. Pressure tested shell and surface line to 1000 psig with 50/50 Methanol, good test. Bied lines down, cooled down N2 unit and pressure up to 850 psig. Open well, WHP=846 psig RIH with coil, Open well to flow back tank, WHP down to 711 psig when coil at 640' GTM. N2 PIP= 175 psig, 350 SCFM. Coil at 4995' CTM, PIP= 490 psig, WHP= 11 psiq. No fluid to flow back tank. N2 at 350 SCFM Fluid to flow back tank when coil at 6800' CTM, fluid muddy. PIP= 1470 psig, 1h+NP @ 10 psig. Still good returns to flow back tank, WHP= 265 psig, PIP= 1540 psig returns clear compared to earlier sample. Tagged fill when coil at 9467, PUH with coil to 9460'_ Bottom of perforations at 9240' DIL. Parked coil and continued to jet N2. 59 bbls returned to flow back tank, increase N2 rate to 750 SCFM. PIP= 1544 psig, WHP= 145 psig. PU coil every 10 minutes while parked. Total fluid to flow back tank at 103 bb{s. WHP= 260 psig, PIP= 995 psig. N2 rate at 750 SCFM, total pumped at 120, 000 SCF. Returns stopped, only POOH with coil. WHP= 215 psig, PIP= 950 psig. Coil tat 9400' CTM. Shut down N2 ~.vhen ccil @ 6740 psig, continue OUH with coil. OOH with coil, Shut in swab valve to rig back injector from well head. Held safety meeting prior to rigging down injector from well. PU injector go to craddle with injector, PU all tools and clean up around well head. PU tree cap and go to well with tree cap to secure well. BJ crew left lease. WHP= 530 psig. MIRU E-line unit on well. Discussed procedure, uptained work permit and held PJSM prior to rigging up on well. RD flow cross from well SD#3 over to well SD~S. Spotfed equipment around well head and rigged up lubricator. MU roller bogies, 1 11116" Pl7 tool string. PT lubrtcator to 3000 psig, Good rest. 1"!29!2007 '?3:57AM i ~ Marathon Oil Gompany~ fJperations Surrar~ary Report.. Page7af8~ Legal We11 Name: SUSAN DIONNE 5 Common Well Name: SUSAN DIONNE 5 Spud Date: 7/13/2046 Event Name: ORIGINAL COMPLETION Start: 8/25/2006. End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number. `1 Date From - To Hours Code Code Phase ~ Qescription of Operations 2/25/2007 i 10:00 - 10:15 ~ 0.25 ~ WORK~ELEC (WREN 10:15 - 11:50 1.58 WORK jELEC WREN 11:50 - 12;3(7 0.67 _ WORK~ ~ELEC WRW 12:30 - 13:45 ' 1.25 WORK ELEC WREN 13:45 - 14:45 1A0 WORK ELEC WREN 14:45 - 15:3Q 0.75 RURD___ ELEC WREN 07:00 - 08:00 I 1.~0 RURD_ COIL CTBG OS:GO - 08:45 Q.75 SAFETY MTG_ CTBG 08:45 - 10:40 1.92 RURD .COIL CTBG 10:40 - 11:00 0.33 TEST_ BOPE CTBG 11:00 - 12:30 ' 1.50 JET N2 CTBG 12:3D - 14:10 ' 1.67 JET_ N2 CTBG 14:10 - 15:40 1 50 JET N2 CTBG 15:40 - 16:40 1..00+ RUNPU COIL CTBG 16:40 - 18:00 1.331 RURD COIL CTBG 5/31/2007 107:00 - 08:00 08:00 - 08:30 08:30 - 10:30 10:30 - 12:00 12:00 - 14:00 14:00- 14:15 14:15 - 15:05 15:05- 15:30 15:30 - 17:00 6(1!2007 07:00 - 08:00 08:00 - 09:00 09:00 - i D:30 10:30 - 11.::30 :11:30 - 12:20 12:20 - 12:55 12:55 - 13:10 13:10 - 14:00 14:00. 14:10 '14:10 -.14:14 1.D0 SAFETY MTG_ CTBG 0.50 RURD COIL CTBG 2.00 RURD COIL CTBG 1.50 RURD_ COIL CTBG 2.00 RURD_ COIL CTBG 6.25 RURD_ COIL CTBG 0,83 1 TEST 80PE CT6G 0.42 1 RURD_ COIL CTBG 1.50 CTB G 1.00 SAFETY MTG_ CTBG Open well to lubricator. WHP= 1472 pstg. Flow line to production was frozen. RlH with logging tools. Start logging at 5600' after correlafing depths to CBE. Found top of water at 5744' KBD. Bottom of upper tubing patch at 5733' - 5745' KBD. Log down to 9350' KBD. Note: some cooling in the bottom of the uP perforations from 8511' - 852T KBD, (6$99' - 6915' DIL}. OOH with logging tools, shut swab valve and rig off of BJ Coil Tech's BOP'S. Complete rig dowm and clean up around well head. Stagged equipment back to SD#~3. WHP= 1500 psiq on SD~5. Start all equipment Issue work permit, held PJSM and discussed operation for today. PU injector and yo to well. MU Bowen connection. BHA 1.75" coil, coif connector, double check valves, crossover and 2.25" nozzle. Open well to gas buster and bleed from 875 psi top 0. Cool down n2. Pressure tested shell and surface line to 1000 psig ,good test. RIH iettinq wl N2. Found fluid level around 2700'. Increase N2 and stow RIH speed to 60'/min. Water returns to buster Continue jetting down to 9300'. Continue jetting wl N2. Finaf stabilized water rate was around 300 BPD water, 100 psi F'JUHP, 750 psi n2 pump pressure. SD N2 and POH. OOH. Final returns = 105 Bols. Well making small amont of aas. Rig back Ct and release crew. Obtain safe work permit, hold PJSM and discussed operation for today. MIRU crane. Pick well house from well. MIRU coil unit, cement equipment, and N2 pumper. PU gas buster, spot choke manifold. RU 2" hardline to choke manifold, coil unit, gas buster, and cement unit. MIRU cement batch mixer. PTest pumps and surface lines to 6000 psi.. PTest flowback lines io 1000. PTest Bowen SOP's dressed for 1-3!4" to 25C} psi lovrl 4500 psi high:. Test good. Shut well in. Suspend operations for the night. Hauling fresh water. Obtain safe work permit, hold PJSM and discussed operation for today. 1.00 RURD_ COIL CTBG MIRU ASP.C liner crew. Finish erecting sidewalls of containment berm, 1.50 RURD_ COIL CTBG PU injector and BHA, dimple on, 3' straight bar, and cement nozzle w{ large jets. 1.00 RURD COIL. CTBG Load coil and test shell to 1500 psi. Test good. Open master valve. (24 turns) Open swab valve (24 turns). WHP 1200 psi. Bieed down thru choke skid to flow back tank. 0.83 RUNPU. COIL CTBG Continue to bleed down ~NH. ,R1H with coil circulation-min rate. 0.58 RUNPU COIL CTBG Pull test @4480'- 4450' 5,000 lbs. 0.25 P.UNPU COIL CTBG Continue RIH. 0.83 RUNPU COIL CTBG Fluid returns to surface. Q.17 .RUNPU COIL CTBG Pul! test X975' 17k. 0.07 RUNPUf~ COIt. CTBG Tag TD @ 9341'. Pull test 17k. 1 V2Rf20@7~72357 AMAM • Marathon Oil Company Operations Summary Report Legal Well Name: SUSAN DIONNE 5' Common Well Name: SUSAN DIONNE 5 Event Name: ORIGINAL COMPLETION Contractor Name: GLACIER DRILLING Rig Name: GLACIER DRILLING Date From - To Hours Code Code Phase 6!1/2007 14:14 - 14:30 0.27 RUNPU COIL CTBG 14:30 - 15:28 0.97 SAFETY MTG_ CTBG 15:28 - 15:52 0.40 PUMP_ CMT_ CTBG 15:52 - 15:55 0.05 PUMP_ CMT_ CTBG 15:55 - 15:56 0.02 PUMP_ CMT_ CTBG 15:56 - 16:19 0.38 PUMP CMT_ CTBG 16:19 - 16:45. 0.43 PUMP CMT CTBG 16:45 - 16:48 0.05 PUMP CMT CTBG 16:48 - 16:55 0.1Z RUNPU COIL CTBG '16:55 - 16:57 0.03 RUNPU C04L CTBG 16:57 - 18:00 1.05 RUNPU COIL CTBG 18:00 - 18:15 0.25 RUNPU COIL CTBG 0 ~ ` 1 18:35 - 20:00 1 .42 J ET_ N2~ CTBG 20:00 - 20:09 0.15 JET I N2, CTBG 20:09 - 21:04 0.92 JET___ • N2 CTBG 21:04 - 21:40 0.60 JET N2 CTBG 21:40 - 22:00 0.33 CTBG 22:OD - 22:20 0.33 RURD_ COIL CTBG 22:20 - 23:00 0.67 RURD_ COIL CTBG 07:00 - 08:00 1.00 SAFETY MTG SLICK 08:00 - 10:00 I 2-001 RURD I SLIK I SLICK '10:00-11:00 1,40 WORK~jSLIK SLICK 11:00'- 11;;34 0.50 WORK~SLIK SLICK 11:30.- 1~.U'© 1.50 WORK SLIK SLICK 13:00 - 14:00 1:00 RURD__ SLIK SLICK 14:00 - 14:30 0.50 RURD COIL CTBG 14:30 - 15:00 0.50 BURG CMT` CTBG Page8of8~ Spud Date: 7/13/2006 Stan: 81251200 End: Rig Release: Group: Rig Number: 1 Description of Operations PUH to 932G`~ Circulate at min. rate. Shut down for "Tool box talk". Discuss cement job. Mixing cement Mixing complete. Pump 2 barrels fresh water ahead of eernent. P mo 1. bbl m .nt slurry. Pump 28.4 bbl fresh water displacement 1 bpm behind cement. At 9 bbls pumped, begin pulling ct nozzle from 9325' to 8090' at 65 fpm Shut down displacement at 28 bbls. PuII slowl up to 8050',. Returns to tank 24.6 bbls. Continue pulling slowly up to 7750'. Cycle pipe. PUH to 6450'. Circulate at min- rate. WOC, for 1 hour. Cool down N2 unit PTest N2 lines. CT parked at 6450', begin jefing N2 down backside @ 1000 scf while taking returns up the CTubing. Need to recover 79 bbls in ctube x 4.5" annulus and 28.4 bbls in Ctubing reel Total 107.4 bbls. Recover 54" ~ 3.56 bbl/in= 192.2 bbls less 88 bbls initial== 104.2 bbls OOH. Increase WHP from 1523 psi to 1815 psi. Close masters and swab vavies. Safety meeting to dicuss rig down. Bleed off N2. RD injector and safe out location for the nighf. Obtain safe work permit, hold PJSM and discussed operation far today.. Position Expro boom truck and use PWS wire line unit PU cross over on top of BJ BOP valve. MU 1 314" Tool string with 2.75" GR, 10' stem to tag TOC. PT lubricator with water. PT to 2000 psig, good test. Open well, WHP= 1800 psig. RIH with tool string, sat down at 1300' KBD. POOH with wire line tool string. Add 1U' stem to tool string, 2.0" GR. Open well RIH with tools down to 8007 KBD. POOH with TS. OOH with tools, RD PWS. BJ coil tech on location. Held PJSM and discussed rigging down and safety related issues. R and-move coil to Vilest side of pad. BJ done rigging down, left lease for house. 41iRNl2007 7:23:57 AAt Daily Summary for Well: SUSAN DIONNE 5 • Report Report MD Summary Date Number 2007 Post-Rid Cam~letion Event ___-~~~~._ 01-Jun-07 22 Install injector on WH. RtH to set cement plug. Spot 21..3 bbls cement plug. PUH to 6450' . Reverse tubing out using P12. Recovered 104.4 bbls. Pressured up WH to 1800 psi. 02-Jun-07 23 MfRU pollard wiretine unit, Tag cement top. Tagged top at 8007' KBD. BJ coil rig down coif tubing unit. 07-Jun-07 24 Bleed IV2 to 1075 psi. Perforate Tyonec interval and flaw test. o ~ a d SARAN PAUN, GOVERNOR ~~A Duj ~D G~47 333 W. 7th AVENUE, SUITE 100 G1OfTC1*11/RQ~/f1*O1V CO~II~'+~+IO~ ANCHORAGE, ALASKA 99501-3539 1`i7~I s ii L` PHONE (907) 279-1433 FAX (907) 278-7542 Ken Walsh Senior Production Engineer Marathon Oil Company PO Box 1949 Kenai, AK 99611-1949 Re: Ninilchik Unit, Tyonek Undefined Gas Pool, Susan Dionne#5 Sundry Number: 307-196 Dear Mr. Walsh: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in -the enclosed form. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659-3607 (pager). As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. e;,,,.A,-P~~. DATED this ~~ day of June, 2007 Encl. a~~-b~ Chairman • M Marathon MARATHON Oil Company June 7, 2007 Tom Maunder AOGCC 333 West 7t" Ave Suite 100 Anchorage, AK 99501 ~~~ E ~' Dear Mr. rt: Alaska Business Unit P.O. Box 1949 Kenai, AK 99611-1949 Telephone 907/283-1311 Fax 907/283-6175 ~~~1 ~JI~hJ ~ ~ 1~~r .~, .,; t~lask~ tll 8i C~a~s ~,,,, u~~~~mission AnchAraQn Attached and submitted for your approval is the Form 10-403 to plug back wet Tyonek perforations and add new perforations in the Susan Dionne #5 wellbore. A procedure and a wellbore diagram are also included. This form is being submitted as a follow-up to the verbal procedure that you granted on 2/28/2007 for this work. Marathon will complete and submit the Form 10-404 for the work once it has received the written approval of this Form 10-403. In a subsequent telephone conversation this morning, you and I agreed that Marathon would submit a Form 10-407 for the completion work on this well up to the point that Marathon asked and was granted the verbal approval to plug back and add new perfs. If you would like any other information, please contact me at 394-3060 or kdwalsh _marathonoil.com. Sincerely, ~~~ w~ Ken D. Walsh Senior Production Engineer Enclosures: 10-403 Sundry cc: AOGCC Well Schematic Houston Well File Operations Procedure Kenai Well File KDW ~,S° 3~7 STATE OF ALASKA ,i3' 6~/a'v' ~~ ~~.. r.,~ b ~ ,/ ALAS OIL AND GAS CONSERVATION COMMISSION J~ APPLICATION FOR SUNDRY APPROVALS !ll~~~ ~~,~ ~~~`, ~ ~ 7Q~~ 20AAC25.280 Ah~y~,., r`:a ~. ~~,- rti.., r_.._._ 1. Type of Request: Abandon ^ Suspend ^ Operational shutdown ^ Perforate Q Waiver ~ ~ Other Alter casing ^ Repair well ^ Plug Perforations ^~ Stimulate ^ Time Extension ^.fClitra~8 Change approved program ^ Pull Tubing ^ Perforate New Pool ^ Re-enter Suspended Well ^ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Marathon Oil Com an Development ^ Exploratory ^ 206-088 3. Address: Stratigraphic ^ Service ^ 6. API Number: PO Box 1949, Kenai Alaska, 99611-1949 50-133-20562-0000 - 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: Spacing Exception Required? Yes ^ No 0 Susan Dionnne #5 ° 9. Property Designation: 10. KB Elevation (ft): 11. Field/Pool(s): CIRI C - 061505 156' KB (21' AGL) Ninilchik Unit / Tyonek Pool 12. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 9,600' ~ 7,987' 8,045' 6,433' Casing Length Size MD TVD Burst Collapse Structural Conductor 91' 20" 91' 91' 3,060 psi 1,500 psi Surface 1,630' 9-5/8" 1,630' 1,298' 5,750 psi 3,090 psi Intermediate 4,788' 7" 4,788' 3,218' 7,240 psi 5,410 psi Production Liner 5,004' 4-1/2" 9,595' 7,982' 8,440 psi 7,500 psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 8,508' - 9,289' 6,895' - 7,676' 4-1/2" L - 80 4,563' Packers and SSSV Type: Packers and SSSV MD (ft): ZXP Liner Packer 4,563' 13. Attachments: Description Summary of Proposal ^ 14. Well Class after proposed work: Detailed Operations Program ~ BOP Sketch ^ Exploratory ^ Development ~ Service ^ 15. Estimated Date for 16. Well Status after proposed work: Commencing Operations: 5/30/2007 Oil ^ Gas ^~ Plugged ^ Abandoned ^ 17. Verbal Approval: Date: 2/28/2 WAG ^ GINJ ^ WINJ ^ WDSPL ^ ~~ Commission Representative: Tom Maunder ~ ~~~ 18. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Kevin Skiba (907) 283-1371 Printed Name Ken D. Walsh Title Senior Production Engineer Signature ~ n ~ A ~ Phone Date (D /7 ~ 20 0 ` ' l~J~ `~ - 907 283-1311 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3i Plug Integrity ^ BOP Test ^ Mechanical Integrity Test ^ Location Clearance ^ Other: ~ ~~~' ~~~ ~ ~ ?~07 Subsequent Form Required: ~~~ APPROVED BY / -~~~~ Approved by: SIGNER THE COMMISSION Date: LV~ 'n Form 10-403 Revised 06/2~ur! ~ ~v~ ~ ~;'~/~ ~ Submit in Duplicate ~~ COILED TUBING SERVICES Marathon Oil Co. Ninilcik Field Susan Dionne 5 Objective Squeeze cement perforations from 8000' -9400' using balanced plug squeeze method. Cement plug will be set off of PBTD. Procedure 1. MIRU CTU and pumping units. 2. RU pumping iron as needed. RU flowback iron for conventional and reverse circulation returns 3. WHA to include 4-1/16", SM Flow Cross, 4-1/16", SM X 4-1/16", lOM DSA and 4- 1/16", lOM Dual-Combi BOP (dressed for 1-3/4" CT). 4. PU injector and add BHA. Nipple up injector to WHA. Toolstring will consist of 1- 3/4" (WT = 0.125") dimple-on connector, 1-3/4" X 3' Straight Bar, and Cementing Nozzle. 5. Insure the high pressure surface filter is removed from pumping iron. 6. Function test BOP 7. Load CTU w/ 50/50. 8. Pressure test surface iron (200 psi/5000 psi). 9. Pressure test WHA and BOP (200/4500 psi) 10. Open WHA and RIH pumping minimum rate water to load wellbore. 11. RIH to 9400'. Pull test & record pickup weight. 12. Break circulation to surface. Continue to circulate bottoms up while blending cement 13. Blend 25 BBL of cement. 14. SURFACE RETURNS DURING CEMENT PUMPING AND PLACEMENT SHOULD BE MONITORED AND RECORDED BY REGULAR TANK STRAPS IN A METERED AND MEASURED FLOWBACK TANK SEPARATE FROM THE MAIN FLOWBACK TANK. A 60 BBL TANK WOULD BE THE OPTIMUM SIZE WITH EITHER BARREL MARKERS EASILY VIEWED INSIDE TANK OR A KNOWN BARREL PER INCH SPECIFICATION SO THAT A MEASURED STICK OR STRAP CAN BE USED. 15. Circulate cement to end of CTU (String #23786 Capacity = 28.4 BBL) taking returns at surface. Spot cement using following volume schedule Stage Volume BBL) Pump Rate Fresh Water 2.0 1.0 BPM Cement 21.3 1.0 BPM Fresh Water 9.0 1.0 BPM • • 16. With 9.0 BBL of fluid pumped behind cement start to PUH @ 65 FPM pumping Fresh Water @ 1.0 BPM. 17. Stop pump w/ a total of 28.0 BBL of fluids pumped behind cement. CT depth @ this time should be 8163' (+/- 25'). 18. PUH to 7950'. 19. Cycle pipe 3 -4 times from 7950 - 7975. 20. PUH to 6450' @ 120 FPM. Have N2 pumping unit cooled down for immediate pumping when CT depth is 6450'. 21. When N2 pump is cooled down start N2 @ 1000 SCFM hold in hole at 6450'. Strap & record return tank volumes to verify fluid return volumes after reverse circulation. 22. When N2 turns the corner decrease N2 rate to 350 SCFM and continue pumping. 23. At 6450' park CT and unload wellbore fluids to 6450' via N2 reverse circulation. Surface returns at 645.0' = 98 BBL + CT Volume (28.3 BBL) =126.3 BBL. DO NOT exceed 2600 psi WHP at any time during reverse circulation procedures to minimize CT collapse potential. 24. With 112 BBL returned to surface RIH to 7150 @ 100 FPM pumping N2 @ 350 SCFM. 25. At 7150' increase N2 rate to 1000 SCFM. When N2 turns corner decrease rate to 350 SCFM. Surface returns at 7150' = 126.3 BBL + 10.6 = 136.9 BBL 26. When returns swap from N2 to fluid RIH to 7900' (or maximum depth specified by MOC) @ 100 FPM. Pumping N2 @ 350 SCFM. 27. Increase N2 rate to 1000 SCFM. When N2 turns the corner decrease rate to 350 SCFM. Surface returns at 7900' = 136.9 BBL + 11.4 = 148.3 BBL 28. When returns swap to straight N2 SI choke manifold to trap N2 pressure at WH. 29. POOH @ 120 FPM. 30. With CT @ surface SI WHA. Marathon Oil wants to trap @ minimum 1300 psi WHP. If WHP is below 1300 psi pump NZ via kill line to exceed 1300 psi WHP. 31. Vent CT pressure to flowback tank. 32. RDMO CTU. • BJ Services Pacific Region Laboratory Report Report #: CMT010507A Date: March 1, 2007 Company: Marathon Oil Co. Prepared for: Ken Walsh Well: Susan Dionne #5 Prepared by: Matt Kedzierski Submitted by: Ken Nix District: Kenai Job Type: CT Plug Tested by: Mike Walley Depth MD: 9600 ft TVD: 7987 ft Casing Size: 4'/s" Hole Size: BHST: 142°F BHCT: 142°F Cement: Class G Lot #: LaFarge Water: Fresh Class G+0.7% FL-63+0.5% R-3+0.3% EC-1+0.3% CD-32+0.1% ASA-301+0.05% Static Free+1 ghs FP-6L [All additive were prehydrated in the mix water] Density: 15.80 ppg Yield: 1.158 ft3/sack Mix Water: 4.902 gal/sack Time to 70bc: 9:29 hr:min [Time does not include 45 minute batch mix] Time to 100bc: 9:33 hr:min Free Water: 0-Tr% @ 45° incl. Fluid Loss: 44 cc/30 min • • . . 1 1 • 1 1 • 1 1 • 1 1 • • • Ambient ~ ~ 142°F 287 170 120 71 11 11 117 53 3500 ~ 50 ~a IQ ,1_, jI 60 I 1500 r 30 I I 30 1000 30 long Notice: This report is presented in good faith based upon present day technology and information provided: but because of variable conditions and other information which must be relied upon, BJ Services makes no warranty, express or implied, as to the accuracy of the data or of any calculations or opinions expressed herein. You agree that BJ Services shall not be liable for any loss or damage, whether due to negligence or otherwise, arising out of or in connection with such data, calculations, or opinions. • Susan Dionne #5 • Ninilchik Unit 150' FSL & 1257' FEL ~~y~ Sec. 6-T1S-R13W S.M. Post- 2007 Proposed Work 5.0 deg/100' from 200-1434' MD 61.5 deg from 1434-2700' MD 2 deg/100' to 5900' M D 1.0 deg from 5900' to TD at 9,600' MD ath: 220.7 deg String - 4.5", 1 Baker Chemical Injection Nipple @ 2385' MD (Top) 5.930" OD/3.858" ID 8430 psi bursU7500 psi collapse ZXP Liner Packer with 15' Tieback Extension @ 4,569' MD (Top) Flex-Lock Liner Hanger @ 4607' MD (Top) PAC valve @ 6984' KB (4' long) Landing Collar @ 9,467' MD (Top) Float Collar @ 9,509' MD (Top) Float Shoe @ 9595' MD (Bottom) Surface Casing 9-518" 40 PPf T~ MD 0' TVD 0' Conductor 20" K-55 133 ppf T~ Bottom MD 0' 91' TVD 0' 91' L$0 BTC Bottom 1630' 1298 12-114" hole with 404 sks (180 bbls) 12 ppg Type 1 cement with 30 bbls 12 ppg cement to surface. with partial lost returns. Intermediate Casing 7" 26 ppf L-80 T~ Bottom M D 0' 4788' TVD 0' 3216' 8-1/2" hole with 254 sks (111.7 bbls) 12.5 ppg Lead + 197 sks (40.9 bbls) 15.8 ppg Tail Bumped plug, 15 bbl contaminate + 5 bbls cement to surface, 100 % returns, floats held BTC PE MD TVD Net Ft 735-~3~ 4123-4125' 2' Owen Squeeze Perfs (3-318" 6 SPF 817/2006) 'atched with Owen 11.75' x 3.80 OD x 3.375" ID (5733'-5744.75') on 10/2612006. 5317-5343' 3714-3739' 26' Proposed "'?~° ~"°' 6660-6667 6' Owen 3-318" 6 SPF 1012&3106 Wet• Patched with Owen 1.75' x 3.80 OD x 3.375" ID (8268'$279.75') on 1 012412 0 0 6 6899-6915' 16' Owen 3-318" 6 SPF 1012/06 7651-7677' 26' Owen 3-3/S" 6 SPF 1012106 Cement Top at 8045' KB 1st Stage Liner Cement Top at E R di KB 2nd Stage 4112" 12.6 ppf L•80 Hydril 563 xpro a al Bon .. d Log : - . _ ... , ~::,,..; ~ ~ ~:' T~ Bottom MD 4569' 9595' Formation Tops: TVD 3028' 7982' 7" hole with 20 bbl 10.5 ppg spacer followed by 330 sks (118.6 bbls) 13.0 ppg Formation Depth (MD) Depth (TVD) 8045' KB cement top from CBL Run 81712006. Lost circ w/83 bbls cmt displaced. Beluga 920 872 PAC valve opened and immediately closed. Tyonek 5006 3418 Perfed 5735-5737' (Owen 3-3/8" 6 spf) to cement above TD 9600 7987 120 sks (43 bbl) 13.0 ppg lead followed by 50 sks (10 bbls) 15.8 ppg tail ' ' 7.6 bbls cement returns to surface. TD: 9600' M D 17987' TVD • Susan Dionne #5 Ninilchik Unit 150' FSL & 1257' FEL i~u-wmioM Sec. 6-T1S-R13W S.M. Current WBD 5-24-2007 ild 5.0 deg/100' from 200-1434' MD Id 61.5 deg from 1434-2700' MD ~p 2 deg1100' to 5900' MD Id 1.0 deg from 5900' to TD at 9,600' MD muth: 220.7 deg String - 4.5", 12.6#, L-80, Buttress Mod String - 4.5", 12.6#, L-80, Hydril 563 r Chemical Injection Nipple @ 2385' MD (Top) 5.930" OD/3.858" ID 8430 psi bursU7500 psi collapse Liner Packer with 15' Tieback Extension @ 4,569' MD (Top) Lock Liner Hanger @ 4607' MD (Top) valve @ 6984' KB (4' long) ing Collar @ 9,467' MD (Top) Collar @ 9,509' MD (Top) Shoe @ 9595' MD (Bottom) Surface Casino 9-5/8" 40 ppf T~ MD 0' TVD 0' Conductor 20" K-55 133 ppf T~ Bottom MD 0' 91' TVD 0' 91' L-80 BTC Bottom 1630' 1298 12-114" hole with 404 sks (180 bbls) 12 ppg Type 1 cement with 30 bbls 12 ppg cement to surface. with partial lost returns. Intermediate Casino 7" 26 ppf L-80 T~ Bottom M D 0' 4788' TVD 0' 3218' 8-112" hole with 254 sks (111.7 bbls) 12.5 ppg Lead + 197 sks (40.9 bbls) 15.8 ppg Tail Bumped plug, 15 bbl contaminate + 5 bbls cement to surface, 100 % returns, floats held BTC PE MD TVD Net Ft Sz35 573 41234125' 2' Owen Squeeze Perfs (3-3/8" 6 SPF 8/7/2006) Patched with Owen 11.75' x 3.80 OD x 3.375" ID (5733'-5744.75') on 10/26/2006. Tvonek Perfs: it Top at 8045' KB 1st Stage it Top at KB 2nd Stage Radial Bond Loq Formation Tops: Formation Death (MD1 Deoth (TVDI Beluga 920 872 Tyonek 5006 3418 TD 9600 7987 5317-5343' 3714-3739' 26' Proposed I °4"'o~"O"O' 6660-6667 6' Owen 3-318" 6 SPF 1012&3106 Wet- Patched with Owen i ` 11.75' x 3.80 OD x 3.375" ID (8268'-8279.75') on 1 012 412 0 0 6 1, 8511.8527' 6899-6915' 16' Owen 3-318" 6 SPF 1012/06 9264.9290' 7651-7677' 26' Owen 3-3/S" 6 SPF 10/2/06 ( Liner 4-112" 12.6 ppf L-80 Hydril 563 T~ Bottom M D 4569' 9595' TVD 3028' 7982' 7" hole with 20 bbl 10.5 ppg spacer followed by 330 sks (118.6 bbls) 13.0 ppg 8045' KB cement top from CBL Run 8/7/2006. Lost circ w183 bbls cmt displaced. PAC valve opened and immediately closed. Perfed 5735-5737' (Owen 3-318" 6 spf) to cement above 120 sks (43 bbl) 73.0 ppg lead followed by 50 sks (10 bbls) 15.8 ppg tail 7.6 bbls cement returns to surface. TD: 9600' MD / 7987' TVD Re: SD #3 and SD #5 Perf Abandonments • Subject: Re: SD #3 and SD #5 PerfAbandonments From: Thomas Maunder <tom_maiulder@admin.state.ak.us> Date: Wed, 28 Feb ?007 14:46:12 -0900 To: "fit alsh. Kcn" <kdwal~h'c;marathorn~il.corn>, AOGCC North Slops Of~fic~~ ~'ao~~cc prudhoc b~y~iadmin.statc.ak.u~-> Ken, ~~~ S aC~~,- ~~ I have looked at what you propose. The goal is to eliminate water production in both wells and you wish to take advantage of the equipment that is currently available. You are correct that sundries need to be filed for the work. However, by copy of this email you may proceed with the plans you have presented. Contact the Inspector regarding tagging the cement. I have copied this message to them. Call or message with any questions. Tom Maunder, PE AOGCC Walsh, Ken wrote, On 2/28/2007 11:51 AM: Tout, VVe would prefer to start the work on the SD on Friday, March 2, since Marathon has a tailed tubing unit and associated equipment already rigged up on the well subsequent to jetting attempts fio unload the produced water. Marathon requests verbal approval to proceed with this work on the SD # It is unclerstoc~cl that Marathon will send in a written Form ~ 0-403 as follow-up to the verbal approval. Marathon also requests verbal approval tc~ run and set the straddle assembly into the D 3 well to shut off the excessive water production from the interval, 0926-6086' KB. 1 of 2 2/28/2007 2:46 PM Re: SD #3 and SD #5 Perf Abandonments i Again, Marathon will fallow-up quickly with a written Form 10-403 submission documenting this verbal approval. Tom, ! would like to discuss with you some questions !have regarding these two Rlinilchik Area wells and the procedures that !have in mind for abandoning "wet" Perf intervals. !can give you a call at a time of your choosing or you are welcome to call me at my office number, 283-13~ ~ , !have attached a spreadsheet that contains wellbore diagrams for the two wells. Regards, ~'1? «SD 3+5 WBDs.xls» 2 of 2 2/28/2007 2:46 PM t ~ r~ L_J 11'1$x'1®11 IIAARATHON II X911'1 December 14, 2006 Alaska Oil & Gas Conservation Commission Attn: Howard Okland 333 W. 7~' Avenue, Suite 100 Anchorage, AK 99501 RE: Marathon Susan Dionne # 5 Well (SD-5) and Marathon Beaver Creek Unit 3RD (BCU-3RD) Well CONFIDENTIAL Dear Mr. Okland: Alaska~et Team United States Production Operations P.O. Box 3128 Houston, TX 77253 Telephone 713-296-3597 Fax 713-296-4469 FedEx ' ' ~~~ 1 ~R "", j ~ t .3. _ ~~?j <- '-~ s~~ ,~~., l .:~ The following confidential digital well data are enclosed for the above referenced wells. SD-5 As-Built Plat ............................................................................ .......................Digital Daily Drilling Reports .............................................................. .......................Digital Directional Survey ................................................................... .......................Digital EPOCH Report/Mud Log Data ................................................ .......................Digital Weatherford Wireline Log Data (See SD-5_Log Summary.xls on CD): MD Photo Density Dual Spaced Neutron ......................... .......................Digital MD Compensated Sonic ................................................... .......................Digital MD Array Induction Vector Processing ........................... .......................Digital MD Array Induction Focussed Electric ............................ .......................Digital Compact Formation Tester ............................................... ....................... Digital TVD Array Induction Focussed Electric ........................... .......................Digital One CD containing the above digital data BC-3RD As-Built Plat ..................................................................................................Digital Daily Drilling Reports ....................................................................................Digital Directional Survey .........................................................................................Digital EPOCH Report/Mud Log Data ......................................................................Digital Halliburton Wireline Log Data (LAS and Scanned Tiffs) .............................Digital One CD containing the above digital data To download the Preview software, which allows access to all Weatherford Wireline data to view and plot logs (LAS, and DPK), follow the link below. http:/'www. Weatherford.com/weatherforcL`groups/public/documentsi""evaluations eds_downloadpreviewsoftware. hcsp SD-5 and BCU-3RD Page 1 of 2 • ~ .. • • Please indicate your receipt of this data by signing below by faxing to me at 713-296-4469 or by sending to my attention at the above address. Thank you, G~~ Courtney McElmoyl Advanced Geoscience Technician Enclosures ~ ~~~ ~ U~~ ~,Q~C~e~ ~~ ~ L e ~ `,1/- ~~ 0~~6 c ~o~ Received by: Date: /~II ~In~~ ~ ,~.$ 3~,;~~ ,~~ ~ , ~~ _ ~. II L., A ~~~~ ~m~®,~ SD-5 and BCU-3RD Page 2 of 2 s~ 9 , ' ~ ~~ 7 i l ~ " f a r ~ ~ ~ ~ ~ ~~ ( ~ ~ ~ ' ~ ~ ~ ~"'~ FRANK H MURKOWSK/ GOVERNOR v _~ y , ,~ ~ ~ ~ . , ~as[1~7JOL'1L O~ ~ ~ 333 W. 7TM AVENUE, SUITE 100 COI~TSERQA'rIO1~T COMI-IISSIOI~T ;f ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 Willard Tank FAx (907) 276-7542 Advanced Senior Drilling Engineer Marathon Oil Company PO Box 3128 Houston, TX 77253 Re: Ninilchik Unit, Tyonek Undefined Gas Pool, Susan Dionne #5 Marathon Oil Company Permit No: 206-088 Surface Location: 150' FSL, 1257 FEL, SEC. 6, T1S, R13W, S.M. Bottomhole Location: 2512 FNL, 3546 FEL, SEC. 7, TIS, R13W, S.M. Dear Mr. Tank: Enclosed is the approved application for permit to drill the above referenced development well. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the Commission reserves the right to withdraw the permit in the event it was erroneously issued. The proposed producing location for this well requires a spacing exception due to proximity to property boundaries, the required order, Conservation Order No. 568 will be approved on July 5, 2006. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659-3607 (pager). Sincerely, ~~ Cathy . Foerster Commissioner DATED this3~ay of July, 2006 cc: Department of Fish 8v Game, Habitat Section w/ o encl. Department of Environmental Conservation w/o encl. M Marathon ~i:aTMO~ Oil Company June 20, 2006 John Norman Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7t" Ave, Suite 100 Anchorage, AK 99501 Reference: Drilling Permit Application Field: Ninilchik Well: Ninilchik Unit -Susan Dionne #5 Dear Mr. Norman Worldwide Drilling North America P.O. Box 3128 Houston, TX 77253-3128 Telephone 713-629-6600 Fax 713-499-6737 ~E~~~~4' ,IUN 2 1 't UOe Alaska ®il & Ges o®aseG~m~s~j9n Anch 9 Enclosed please find the PERMIT TO DRILL application, along with the associated attachments and filing fee of $100. The intent is to drill a Tyonek exploitation well. If you require further information, I can be reached at 713-296-3273 or by a-mail at wjtank@marathonoil.com. Sincerely, Willard J. Tank Advanced Senior Drilling Engineer Enclosures STATE OF ALASKA ~~(, ~3°! ~ 4 ALA OIL AND GAS CONSERVATION COM ION PERMIT TO DRILL 20 AAC 25.005 1a. Type of Work: Drill Q Redrill ^ Re-entry ^ 1b. Current Well Class: Exploratory ^ Stratigraphic Test ^ Service ^ Multiple Zone ^ Development Oil ^ Development Gas Q Single Zone Q 1 c. Specify if well is proposed for: AnC~l0lage Coalbed Methane ^ -Gas Hydrates ^ Shale Gas ^ 2. Operator Name: Marathon Oil Company 5. Bond: Blanket ~ Single Well ^ Bond No. 5194234 11. Well Name and Number: Ninilchik Unit -Susan Dionne #5 3. Address: P.O. Box 3128, Houston, TX 77253 6. Proposed Depth: MD: 9,618 TVD: 8,000 12. Field/Pool(s): Ninilchik Unit 4a. Location of Well (Governmental Section): Surface: 150' FSL, 1,257' FEL, Sec. 6, T1S, R13W, S.M. 7. Property Designation: CIRI Lease C-061505 (ct_o Loc ~, Sec 7, T1S, R13W) Tyonek Pool Top of Productive Horizon: 2,371' FNL, 3,424' FEL, Sec. 7, T1 S, R13W, S.M. 8. Land Use Permit: 13. Approximate Spud Date: June 28, 2006 Total Depth: 2,512' FNL, 3,546' FEL, Sec. 7, T1 S, R13W, S.M. 9. Acres in Property: 694.78 14. Distance to Nearest Property: 270 ft (small fee leases) 4b. Location of Well (State Base Plane Coordinates): Surface:x - 213,176.667 y - 2,236,631.970 Zone - 4 10. KB Elevation (Height above GL): (21' AGL) 156 feet 15. Distance to Nearest Well Within Pool: 2,544 ft to SD #4 16. Deviated wells: Kickoff depth: 200 feet Maximum Hole Angle: 61.264 degrees 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Downhole: 3,744 Surface: 2,509 18. Casing Program: Specifications Top -Setting Depth -Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) Driven 20" 133 L-80 PE 70' 0' 0' 91' 91' 12 1/4" 9 5/8" 40 L-80 BTC 1,602' 0' 0' 1,623' 1,300' 407 sacks 8 1/2" 7" 26 L-80 BTC 4,747' 0' 0' 4,768' 3,200' 329 sacks 7" 4 1/2" 12.6 L-80 Hydril 563 5,068' 4,550' 3,009' 9,618' 8,000' 510 sacks 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry O perations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): 20. Attachments: Filing Fee Q BOP Sketch Q Drilling Program Q Time v. Depth Plot ^ Shallow Hazard Analysis ^ Property Plat^ Diverter Sketch^ Seabed Report ^ Drilling Fluid Program Q 20 AAC 25.050 requirements ^ 21. Verbal Approval: Commission Representative: 22. I hereby certify that the foregoing is true and correct. Printed Name Willard J. Tank Signature Date Contact Title Advanced Senior Drilling Engineer Phone 713-296-3273 Date June 20, 2006 Commission Use Only Permit to Drill Number: ~ ~- ~ API Number: 50- / - „2Q S Permit Approval Date: See cover letter for other requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce Coalbed methane, gas hydrates, or gas contained in shales: Other: ~ j e~~- >t3o P ~ -~ ~j r7~D ~ ~ ~ Samples req'd: Yes^ N Mud log req'd: Yes^ No l HZS measures: Yes^ No Directional svy req'd: Yes No^ APPROVED BY THE COMMISSION DATE: ?- 3 ~© ,COMMISSIONER R~~~°° JUN 2 1 2006 Alaska Oi! ~ Gas Con . Form 10-401 Revised 12/2005 ~ _~ > ~ ~ Submit in Duplicate Susan Dionne #5 ~ • Drilling Program / ~ MARATHON MARATHON OIL COMPANY DRILLING PROGRAM Susan Dionne #5 Originator: Will Tank June 20, 2006 Date Reviewed by: Pete Berga Date Brian Roy Date Marathon Oil Company Northern Business Unit ~ 6/20/2006 CONFIDENTIAL MATERIAL Page 1 of 19 Susan Dionne #5 • ~ Marathon Oil Company Drilling Program Northern Business Unit TABLE OF CONTENTS 1. Emergency Response Information .................................................................................................................. 4 1.1 Directions to Location ...................................................................................................................................... 4 1.2 Rig Contact Numbers ...................................................................................................................................... 4 1.3 Marathon Emergency Response Contacts ..................................................................................................... 4 1.4 Outside Emergency Response ....................................................................................................................... 4 1.5 Marathon Contact List ..................................................................................................................................... 5 2. Regulatory Agency Contacts .......................................................................................................................... 5 2.1.1. Internal Regulatory Contact ............................................................................................................................ 5 2.1.2. External Regulatory Contact ........................................................................................................................... 5 3. Regulatory Compliance ................................................................................................................................... 5 4. Drilling Program Summary .............................................................................................................................. 6 4.1 General Well Data ........................................................................................................................................... 6 4.2 Working Interest Owners Information ............................................................................................................ . 6 4.3 Geologic Program Summary ......................................................................................................................... .. 6 4.4 Summary of Potential Drilling Hazards ......................................................................................................... .. 7 4.5 Formation Evaluation Summary ...................................................................................................................... 7 4.6 Drilling Program Summary .............................................................................................................................. 8 4.7 Casing Program Summary ............................................................................................................................ 10 4.8 Casing Design ............................................................................................................................................... 10 4.9 Calculation of Maximum Anticipated Pressures (MAWP and MASP) ........................................................... 10 4.10 Casing Test Pressure Calculations ......................................................................................................:........ 12 4.11 Blowout Prevention Equipment, Testing and General Procedures ............................................................... 12 4.11.1. Function Testing ............................................................................................................................................ 12 4.11.2. Pressure Testing ........................................................................................................................................... 13 4.12 Wellhead Equipment Summary ................................................................................................................... 13 4.13 Directional Program Summary ...................................................................................................................... 13 4.14 Directional Surveying Summary .................................................................................................................... 14 4.15 Drilling Fluid Program Summary ................................................................................................................... 15 4.16 Drilling Fluid Specifications ........................................................................................................................... 15 4.17 Solids Control Equipment .............................................................................................................................. 16 4.18 Cement Program Summary .......................................................................................................................... 17 4.19 Regulatory Waivers and Special Procedures ............................................................................................... 17 4.20 Bit Summary .................................................................................................................................................. 18 4.21 Hydraulics Summary ..................................................................................................................................... 18 4.22 Formation Integrity Test Procedure .............................................................................................................. 19 6/20/2006 CONFIDENTIAL MATERIAL Page 2 of 19 Susan Dionne #5 Drilling Program Marathon Oil Company Northern Business Unit Attachments Grou Attachment Attached Commercial Information AFE Da s/Cost vs. De th Curves X Pro'ect Ob'ectives and Scorecard RSO Codin Information X Re uisitions Vendor List Bonus Pro ram Drillin Contract Re ulato / HES Information Emer enc Evacuation Plan X H2S Contin enc Plan n/a Re ulato Permits X Re ulato Rules and Re ulations Risk Anal sis Miscellaneous Pro rams Vendors Bit Pro osal X Cement Pro osal X Directional Plan X Fluids Pro ram X Wellhead E ui ment - Descri tion/Drawin s Drill Strin and BHA Summa Ri Mobilization/Moorin Procedure n/a Geolo ical Information Location Ma w/ offsets X Offset Data Pro osed Formation Pore Pressure, Mud Wt & Fracture Gradient X Tem erature Curves Geolo is Structure Ma s Geolo is Cross Section Bath et Ma n/a Anal sis Riser Anal sis n/a Station Kee in Anal sis - Moorin /DP n/a Stress Check Casin Desi n File X Maximum Allowable Over ull Miscellaneous Information Wellbore Dia ram n/a Ri Elevations X Well Location Dia ram X BOP Schematic X BOP Well Control Brid in Document Detailed Casin S ecifications X Detailed Drill Pi e S ecifications 6/20/2006 CONFIDENTIAL MATERIAL Page 3 of 19 Susan Dionne #5 Drilling Program Marathon Oil Company Northern Business Unit 1. Emergencv Response Information 1.1 Directions to Location Method Directions Air Latitude - 60°06'46.740"N Longitude - 151 °34'20.265"W From the Kenai airport, go 0.5 mile South on Willow Street. Turn Easton Main Street Loop, go 0.3 miles. Continue Easton Ground Bridge Access Road 3.2 miles. Turn West on Kalifornsky Beach Road. Go West and then South, go 16.9 miles. Turn South on Sterling Highway, go 18.8 miles. Turn West onto road to the pad (Sterling Highway milepost 128.6). 1.2 Rig Contact Numbers Contact Office Cetl Glacier Drilling Rig 1 Inlet Drilling Tool Pusher 907-283-1314 907-394-1321 Marathon Supervisor 907-283-1312 907-394-1317 1.3 Marathon Emergencv Response Contacts Individual Postion Main Phone Alternative Kenai Gas Field Emergency Number 907-283-6465 CERT 24 hrs Notlfication 1-800-MOC-CERT CERT Crisis Center Houston 713-296-4230 713-296-4237 1.4 Outside Emergencv Response Location Contact Phone Fire Kenai /Soldotna, Alaska 907-262-4792 Ambulance Hospital Kenai /Soldotna, Alaska Central Peninsula Hospital 907-262-4404 Police Kenai /Soldotna, Alaska Kenai Police Soldotna Police State Police 907-283-7879 907-262-4455 907-262-4453 Coast Guard 800-478-5555 Spill and Contamination Alaska Alaska State Spill Reporting National Response Center Oil /Toxic Chemical Spills 800-424-8802 Best Practices: 1 Policy: Post emergency notification information on rig floor, company man's and tool pushers' office Comments: 6/20/2006 CONFIDENTIAL MATERIAL Page 4 of 19 Susan Dionne #5 Drilling Program Marathon Oil Company Northern Business Unit 1.5 Marathon Contact List Contact Title Office Mobile Facsimile Home Will Tank Drilling Engineer 713-296-3273 713-203-8398 713-499-6737 832-934-2617 Pete Berga Drilling Superintendent 907-565-3032 907-529-0551 907-565-3076 907-346-3763 Bryan Roy Drilling Manager 713-296-3256 832-444-4772 713-499-6707 281-246-4686 Jennifer Enos Geologist 713-296-3319 713-408-3583 Clyde Scott Reservoir Engineer 713-296-2336 Ken Walsh Production Engineer 907-283-1311 907-394-3060 907-283-3050 Dave Morris Drilling Supervisor 907-283-1312 907-398-0281 907-283-1313 John Nicholson Drilling Supervisor 907-283-1312 907-283-1313 2. Reaulatorv Agency Contacts 2.1.1. Internal Resalulatory Contact Contact Title Office Phone Cell Phone Home Phone Facsimile Chick Underwood Re ulato Compliance 713-296-3254 979-830-7927 979-836-9390 713-499-6748 2.1.2. External Regulatory Contact Contact Title Office Phone Facsimile 24 hr Emer en Pa er AOGCC 907-793-1236 BLM 907-267-1442 3. Regulatory Compliance Regulation Requirement 20 AAC 25.035 a 10 A BOP testing interval requirement is now 14 days. 20 AAC 25.035 a 10 F Requirement fora 24 hour notice to AOGCC prior to BOP test. Comments 6/20/2006 CONFIDENTIAL MATERIAL Page 5 of 19 Susan Dionne #5 Drilling Program 4. Drilling Program Summary 4.1 General Well Data Marathon Oil Company Northern Business Unit Well Name Susan Dionne #5 Lease /License Surface Location 150' FSL, 1,257 FEL, Sec. 6, T1S, R13W, S.M. WBS Code DX.04.11009.CAP.DRL Slot/Pad Susan Dionne Pad Field Ninilchik Unit Spud Date 06/29/06 (est.) KB (above MSL) 156' County/Province Kenai Peninsula API No. GL (above MSL) 135' State /Country Alaska Permit No. Perm. Datum KB Total MD 9,618' Weil Ciass Exploitation Water Depth N/A Total TVD 8,000' Rig Contractor Glacier Drilling Water Protection Depth Rig Name Glacier Rig 1 Best Practices: Comments: 4.2 Working Interest Owners Information Com an Workin Interest Address Phone Facsimile Marathon 60% P.4• Box 196168 907-561-5311 907-565-3076 Anchora e, AK 99519-6168 Chevron -Texaco 40% 4.3 Geologic Program Summary Surface Location Coordinates From Lease/Block Lines 150' FSL, 1,257' FEL, Sec. 6, T1 S, R13W, S.M. Latitude 60° 06' 46.740" N .Longitude 151 ° 34' 20.265" W UTM North (Y) 2,236,631.970' UTM East (x) 213,176.667' Tolerance Pore Pore MD -RKB TVD -RKB Pressure Pressure Possible Formation (ft) (ft) (psi) (p ) Lithology Fluid Content Beluga (Not a Prod Target) 953 900 8.46 Sandstone Gas/Water Tyonek (Primary Target) 5,078 3,483 9.00 Sandstone Gas s/2o/2oos CONFIDENTIAL MATERIAL Page 6 of 19 Susan Dionne #5 Drilling Program Marathon Oil Company Northern Business Unit Depth (KB) Horizontal Displacement (ft Target MD (ft) TVD (ft) Location +N/-S (Y +E/-W (X) Tolerance (ft) Tyonek 5,078 3,483 2,371' FNL, 3,424' FEL, Sec. 7, T1S, R13W, S.M. -2,521 -2,167 Circle 200' radius Tyonek T-2 5,740 4,123 2,493' FNL, 3,530' FEL, Sec. 7, T1S, R13W, S.M. -2,643 -2,273 Circle 200' radius Tyonek T-3 7,339 5,721 2,512' FNL, 3,546' FEL, Sec. 7, T1S, R13W, S.M. -2,662 -2,289 Circle 200' radius TD 9,618 8,000 2,512' FNL, 3,546' FEL, Sec. 7, T1S, R13W, S.M. -2,662 -2,289 Circle 200' radius 4.4 Summarv of Potential Drilling Hazards Hazard Event De(T~hDjB Discussion Precautions Bit or BHA balling Surface Hole Maintain high pump rates to keep bit and BHA clean. Use extra circulation time if necessary. Excessive Torque Intermediate & Production Use good hole cleaning techniques with high pump Excessive. pumping on bottom could Hole rates. Add lubricant where necessary. result in hole washout. Potential Hazards Statement To comply with state regulations the Potential Hazards section and the well shut-in procedures must be posted in the drillers dog house. The man on the brake (driller or relief driller) is responsible for shutting the well in (BOPE or diverter as applicable) as soon as warning signs of a kick are detected and an influx is suspected or confirmed. A copy of the approved permit to drill must be kept on location and be readily available to the AOGCC inspector. This well's primary objective is gas and no oil sands are expected to be encountered. No H2S is anticipated. Gas sands will be encountered from +/- 2,039' MD (1,500' TVD) to total depth of the well. These sands will run from slightly depleted to slightly above normal pressure. The Flo-Pro mud system that will be properly weighted to hydraulically control all sands and lost circulation materials will be available on location, if required. Best Practices: 1 Comments: 4.5 Formation Evaluation Summary Interval LWD Electric Logs Mud Logs Surface None None None 0' - 1,623' MD Intermediate None Reeves Quad Combo. Pull GR-Neutron to Basic with GCA, shale density, temperature in and 1,623' - 4,768' MD surface inside casing. out, sample collection (10' samples). Production None Reeves Quad Combo, MFT, Dipmeter. 4,768' - 9,618' MD Pull GR-Neutron to tie into Intermediate Basic with GCA, shale density, temperature in and run. Schlumberger DSI in 7" casing to out, sample collection (10' samples). surface shoe. Completion N/A GR, CCL, CBL N/A Comments: 6/20/2006 CONFIDENTIAL MATERIAL Page 7 of 19 Susan Dionne #5 • Marathon Oil Company Drilling Program Northern Business Unit 4.6 Drillins~ Prostram Summary Drive Pipe: N/A Conductor: 20" set to approximately 100', prior to drilling rig move. MIRU drilling rig. NU diverter. 1. RU crane and hammer. Drive 20" conductor to +/-100 ft. RKB. RD crane and hammer. 2. Move in and rig up rotary drilling rig. 3. Install starting head 20" SLC x 21 1/4", 2M flanged. 4. Nipple up 21 1/4", 2M diverter, 16" diverter valve, and 16" diverter line. 5. Function test diverter and diverter valve. Best Practices: 1 Comments: Surface: Drill 12-1/4" hole to +/- 1,623' set 9-5/8" casing. 1. Drill a 12 1/4" hole to 1,623' MD (1,300' TVD) per the directional plan. 2. Run and cement 9 5/8" casing. 3. Cut off 9 5/8" casing. ND diverter. 4. Install 9 5/8" slip lock connection X 11" 5M flanged multibowl wellhead. 5. NU 11" 5M X 13 5/8" adapter spool. NU 13 5/8" 5M BOP'S. Test BOP's and choke manifold to 250/3,000 psi. 6. Set wear bushing. Test surface casing to 1,500 psi. Best Practices: 1 During cementing operations, take returns in the cellar, instead of into the pits. Eliminates the clean up of pits from cement that circulated to surface. Vac trucks will pull from cellar. Comments: Intermediate: Drill 8-1/2" hole to +/- 4,768' set 7" casing. 1. PU 8 1/2" PDC bit and directional BHA. Drill out float equipment and 20' of new formation. CBU. 2. Test shoe to leak off. Estimated EMW is 18.5 ppg. 3. Drill 8 1/2" directional hole to 4,768' MD (3,200' TVD) as per directional program, short tripping as required. 4. At TD circulate hole clean. Make wiper trip. TOOH. 5. RU logging company. Run open hole logs on drill pipe utilizing the shuttle system. TOOH with logging tool. Pull wear bushing. 6. Change out pipe rams with 7" casing rams in single ram. Run test plug and test casing rams to 3,000 psi. 7. Run and cement 7" casing. Land hanger in multibowl wellhead. 8. Back out landing joint. Change out 7" casing rams with pipe rams. Run test plug and test BOP's to 250/3,000 psi. 9. Set wear bushing. Test intermediate casing to 2,500 psi. Best Practices: 1 Pre-heat mud mix water to help in early shaker screen blinding issues with the mud. Comments: Production Liner: Drill 7" hole to +/- 9,618' set 4-1/2" liner. Tie back to surface with 4-1/2" tubing. 1. PU 6 1/8" bit and directional BHA. Drill float equipment and 20' of new formation. CBU. 2. Test shoe to leak off. Estimated EMW 16.5 ppg. TOOH to change out bit for 7" hole. 6/20/2006 CONFIDENTIAL MATERIAL Page 8 of 19 Susan Dionne #5 • ~ Marathon Oil Company Drilling Program Northern Business Unit 3. PU 4 3/4" pilot bit, 6" X 7" DOSRWD2 and directional BHA. 4. Drill a 7" hole to an anticipated TD of 9,618' MD (8,000' TVD) as per the directional program, short tripping as required. 5. At TD circulate hole clean. Make wiper trip. TOOH. 6. RU logging company. Run open hole logs as per plan. RD logging company. 7. TIH w/ 6 1/8" tri-cone bit to TD for wiper trip. TOOH and laydown BHA and drill pipe. Pull wear bushing. 8. RU and run 4 1/2" Hydril 563 casing liner with hanger and liner hanger packer on drill pipe. Place pressure activated cementing tool (DV tool) in the liner string so that it will be at approximately 7,123' MD (5,500' TVD). Run liner to TD. On bottom reciprocate and rotate liner while circulating the hole. 9. RU cementing company. Cement 15t Stage of 4 1/2" while reciprocating and rotating pipe. Drop wiper plug and bump plug to pressure up set the liner hanger (liner top at approx. 4,550' MD (3,009' TVD)) and then open the DV tool. Circulate hole clean above DV tool. WOC. Cement 2"d Stage. Drop wiper plug to displace pipe and shift DV tool closed. (see detailed DV tool procedure) 10. Circulate hole clean. If cement circulates, TOOH. If cement doesn't circulate, WOC, then prepare and pump liner top job. 11. Once cement is either circulated or the liner top is squeezed, PU mill for 4 1/2" along with string mill for 7" casing. Make cleanout trip to top of 4 1/2" liner with mill combo on drill pipe. Polish 4 1/2" liner seal bore. 12. Run 4 1/2" liner hanger packer with hydraulic pusher tool. Stab into polish bore receptacle and set packer. TOOH laying down drill pipe. 13. Run 4 1/2" tubing with seal unit. Displace hole with 6 %KCL. Space out tubing and land hanger. ND BOP, NU tree and test to 5,000 psi. 14. Rig down and move out drilling rig. Best Practices: 1 Drill out the shoe track with a 61/8" mill tooth or insert bit to eliminate damage to the 6" x 7" RWD system that occurs in the casing where the bit offset causes excessive contact with casing. 2 In order to fully utilize one 6" x 7" RWD system, BOP testing should occur prior to drilling the production section if there is any chance it will be needed during this hole section. 3 Make up torque shown for the Hydril 563 is 80% of yield. The final make up torque for the liner should exceed any potential torque that would be used to release the running tool from the hanger. Comments: Completion: Completion will be done without a rig. The completion will encompass work to run a cement bond log, displace the KCL water in the wellbore with nitrogen, perforate several Tyonek intervals, and test the well for rate and pressure. No stimulation of the perforating intervals is anticipated. Best Practices: 1 Comments: 6/20/2006 CONFIDENTIAL MATERIAL Page 9 of 19 Susan Dionne #5 Drilling Program 4.7 Casing Pros>Iram Summary c: Marathon Oil Company Northern Business Unit MD (ft) Connection A PI Ratings Casing Size (in) Top Bottom Weight {Ibs/ft) ID (in) Drift (in) Grade Type O. D. (in) Makeup Torque (ft-Ibs) Hole Size (in) rn .-. m' a c .-. ~ a o y H x 9 5/8 0 .1,623 40 .8.835 8.679 L-80 BTC 10.625 N/A * 12 1/4 5,750 3,090 979 7 0 4,768 26 6.276 6.151 L-80 BTC 7.656 N/A * 8 1/2 7,240 5,410 667 41/2 4,550 9,618 12.60 3.958 3.833 L-80 Hydril563 5.2 10,080 7 8,430 7,500 288 Best Practices: 1 Have float equipment made up at Tubescope's yard prior to bringing casing to location. Buck on all equipment to the pin end and not make up to box below, due to rig height restrictions. 2 Make up torque shown for the Hydril 563 is 80% of yield. The final make up torque for the liner should exceed any potential torque that would be used to release the running tool from the hanger. * -Make up buttress connection to proper mark, not to a torque value. Comments: 4.8 Casing Design Casing Shoe Safety Factors Setting Maximum Casing Depth Mud Wt Fran Form Surface a~ o, ~ g Size Weight TVD When Set Grad Press Pressure ~ `-3° (in) (Ib/ft) Grade (ft) (Ib/gal) (Ib/gal) (Iblgal) (psi) °D U ~' 9 5/8 40 L-80 1,300 9.4 18.5 8.5 1,128 2.23 4.87 3.57 7 26 L-80 3,200 9.8 16.5 8.7 2,509 2.73 3.32 2.70 41/2 12.60 L-80 8,000 9.8 16.5 9.0 2,509 1.10 1.84 1.85 4.9 Calculation of Maximum Anticipated Pressures (MAWP and MASP) Setting Casing Depth Size TVD MAWP * MASP "* Mud/Gas (in) ft) (Psi) (Psi) Percentage 9 5/8 1,300 3,951 1,128 0/100 7 3,200 5,001 2,509 0/100 4 1/2 8,000 5,001 2,509 0/100 MAWP =Maximum allowable working pressure ** MASP =Maximum anticipated surface pressure 6/20/2006 CONFIDENTIAL MATERIAL Page 10 of 19 Susan Dionne #5 ~ M Drilling Program Surface casing: 9 5/8" (1.623' MD. 1,300' TVD) MASPfrac =((Fracture gradient at shoe + S.F.) x .052 x NDsnoa) -Hydrostatic pressure of gas column at the shoe. MASPfrac = (18.5 ppg + 0.5 ppg) x .052 x 1,300' - (.1 pSi/ft x 1,300') MASPfrac = 1,284 pSl - 130 pSl MASPfrac = 1,154 psi. MASPbnp = BHPope~ noia m -Hydrostatic pressure of a gas column MASPbnp = (8.7 ppg x .052 x 3,200') - (0.1 psi/ft x 3,200') MASPbnp = 1,448 psi - 320 psi MASPbnp = 1,128 psi MASP =MASPbnp = 1,128 psi MAWP = (0.7 x Casing Burst) - (Mud Wt. -Backup Fluid Wt.) x .052 x ND MAWP = (0.7 x 5,750) - (9.4 - 8.3) x .052 x 1,300' MAWP = 4,025 psi - 74 psi = 3,951 psi Intermediate casing: 7" (4.768' MD. 3.200' TVD) MASPfrac =((Fracture gradient at shoe + S.F.) x .052 x TUDsnoe) -Hydrostatic pressure of gas column at the shoe. MASPfrac = (16.5 ppg + 0.5 ppg) x .052 x 3,200' - (.1 psi/ft x 3,200') MASPfrac = 2,829 psl - 320 psi MASPfrac = 2,509 psl. MASPbnp = BHPopan node ro -Hydrostatic pressure of a gas column MASPbnp = (9.0 ppg x .052 x 8,000') - (0.1 psi/ft x 8,000') MASPbnp = 3,744 psi - 800 psi MASPbnp = 2,944 psi MASP =MASPfrac = 2,509 psi MAWP = (0.7 x Casing Burst) - (Mud Wt. -Backup Fluid Wt.) x .052 x TVD MAWP = (0.7 x 7,240) - (9.8 - 9.4) x .052 x 3,200' MAWP = 5,068 psi - 67 psi = 5,001 psi Production liner: 4 1/2" (Top - 5.900' MD. 3.404' TVD~(Bottom - 9.618' MD. 8.000' TVD) MASP = MASP95ia• = 2,509 psi MAW P = MAW P9 sie° = 5,001 psi Best Practices: 1 Comments: Marathon Oil Company Northern Business Unit 6/20/2006 CONFIDENTIAL MATERIAL Page 11 of 19 Susan Dionne #5 Drilling Program Marathon Oil Company Northern Business Unit 4.10 Casino Test Pressure Calculations Casing test pressures are based on the lesser of (1) MASP, or (2) 70% of rated burst pressure of the casing adjusted for the mud weight used during the test less a 8.3 ppg back-up unless otherwise noted. Best Practices: 1 Comments: 4.11 Blowout Prevention Eauipment. Testina and General Procedures BOP PROGR AM Casing Test Test Casing Test Fluid Pressure Size MAWP MASP press Density BOPS Low/High Casing (in) (psi) (psi) (psi) Ib/gal} Size & Rating (psi) (1) 13-5/8" 5M annular (1) 13-5/8" 5M pipe ram Surface 9 5/8 3,951 1,128 3,000 9.4 (1) 13 5/8" 5M blind ram 250/3,000 (1) 13-5/8" 5M drilling spool with 3-1/8" 5M outlets (1) 13-5/8" 5M pipe ram (1) 13-5/8" 5M annular (1) 13-5/8" 5M pipe ram Intermediate 7 5,001 2,509 3,000 9.8 (1) 13 5/8" 5M blind ram 250/3,000 (1) 13-5/8" 5M drilling spool with 3-1/8" 5M outlets (1) 13-5/8" 5M pipe ram (1) 13-5/8" 5M annular (1) 13-5/8" 5M pipe ram Production 4 1/2 5,001 2,509 3,000 9.8 (1) 13 5/8" 5M blind ram 250/3,000 (1) 13-5/8" 5M drilling spool with 3-1/8" 5M outlets (1) 13-5/8" 5M pipe ram Blowout Preventers The blowout preventer stack will consist of a 13-5/8" x 5000 psi annular preventer, a 13-5/8" x 5000 psi double gate ram type preventer with blind rams in the bottom and pipe rams in the top, a 13-5/8" x 5000 psi drilling spool (mud cross) with 3-1/8" x 5000 psi outlets, and a 13-5/8" x 5000 psi single pipe ram. The choke manifold will be rated 3-1/8" x 5000 psi. It will include a remote hydraulic actuated choke and a hand adjustable choke. Also included is a poor-boy gas buster, and avacuum-type degasser. A flow sensor will be installed in the flowline and the mud pits will contain sensors to measure the volume of fluid in the surface mud system. Both sensors will contain readouts convenient to the drillers console. 4.11.1. Function Testina Function Regularly. 6/20/2006 CONFIDENTIAL MATERIAL Page 12 of 19 Susan Dionne #5 ~ ~ Marathon Oil Company Drilling Program Northern Business Unit 4.11.2. Pressure Testing The Marathon Drilling Supervisor will verify all pressure tests of BOP's, surface lines, seals, casings and FIT or LOT tests. All tests are to be recorded on the IADC and daily drilling reports. Best Practices: 1 Comments: 4.12 Wellhead Equipment Summary Component Description Casing Hanger Type Casing Head 11" 3M X 9-5/8" Slip Loc W/ 2, 2" LPO, Landing Base for 20" Conductor, U, AA, PSL1, PR1 10 3/4" x 7" Fluted Mandrel Tubing Head 11" 3M Studded Bottom X 11" 5M Flg Top, W/ 2, 2-1/16" 5M Studded Outlets, U,AA,PSL1,PR1 11" x 4 1/2" Manual Slip Adapter Flange 11" 5M X 4-1/16" 5M W/ Seal Pocket and 3" H BPV Threads Best Practices: 1 Comments: Use a drilling spacer spool on the 9-5/8" casing head to allow for a B-Section contingency. 4.13 Directional Program Summary Build Tum Coordinates Sec. No. Descxiption MD (ft) TVD (ft) Rate (°/100') Rate (°l100') Dogleg (°/100') Inclination (deg) Azimuth (deg) +N/-S (ft) +E/_yy (ft) VS eft) 1 Tie On 0 0 0 0 0 0 220.689 0 0 0 2 KOP 200.00 200.00 0 0 0 0 220.689 0 0 0 3 Build up Section 5.00 0 5.00 220.689 4 End of Build 1,425.29 1,204.79 5.00 0 5.00 61.264 220.689 -451.16 -387.91 594.99 5 Hold Section 0 0 0 61.264 220.689 6 End of Hold 3,054.40 1,988.02 0 0 0 61.264 220.689 -1,534.31 -1,319.22 2,023.47 7 Drop Section -2.00 0 2.00 220.689 8 End of Drop 6,117.61 4,500.00 -2.00 0 2.00 0.00 220.689 -2,662.20 -2,289.00 3,510.96 9 TD 9,617.61 8,000.00 0 0 0 0.00 220.689 -2,662.20 -2,289.00 3,510.96 6/20/2006 CONFIDENTIAL MATERIAL Page 13 of 19 Susan Dionne #5 Drilling Program • Marathon Oil Company Northern Business Unit Comments: Vertical section calculated from a reference azimuth of 220.69° taken from surface location to bottom hole location. Potential Well Interference: Well Distance (ft) Depth (MDl Susan Dionne #1 171.37 805 Susan Dionne #2 175.47 137 Susan Dionne #3 207.19 Surface Susan Dionne #4 84.40 341 No serious interference exists. See attached directional plan and anticollision analysis for more details. Best Practices: 1 Comments: 4.14 Directional Surveying Summary Interval MD (ft) MWD Survey Magnetic Multishot Gyro Multishot Other Survey Tool Remarks Surface 0 - 1,623' X Intermediate 1,623'-4,768' X Production 4,768' - 9,618' X Best Practices: 1 6/20/2006 CONFIDENTIAL MATERIAL Page 14 of 19 Susan Dionne #5 Drilling Program Comments: ~ • 4.15 Drillin Fluid Pro ram Summa Marathon Oil Company Northern Business Unit Interval - TVD Minimum Inventory From To Density Gel (ft) (ft} (Ib/gal) Fluid Description Additives Viscosifier Barite Gel, Gelex, Soda Ash, Caustic, Barite, Polypac 0 1,300 8.6 - 9.4 Gel / Gelex Spud Mud Supreme UL, Sodium Meta Bisulfate Flo-Vis, Polypac UL, KCI, SafeCarb 10, Asphasol 1,300 3,200 9.4 - 9.8 6% Flo-Pro w/ SafeCarb Supreme, Caustic, Conqor 404, Sodium Meta Bisulfate, Klagard Flo-Vis, DualFlo, KCI, Greencide 25G, SafeCarb 3,200 8,000 9.4 - 9.8 6% Flo-Pro w/ SafeCarb 10, Asphasol Supreme, Barite, Caustic, Conqor 404, Sodium Meta Bisulfate, Lubetex Best Practices: 1 Comments: 4.16 Drilling Fluid Specifications Interval - TVD LSRV Drill From (ft) To (ft) Density (Ib/gal) Vis (sec/gt) 1 min (Ib./100ft~) PV (cP) YP (Ib/100 ft2) Fluid Loss (cc) pH Solids (%) 0 1,300 8.6 - 60 - 100 N/A 25 - 35 NC - 12 +/- 9.5 < 7 1,300 3,200 9.4 - 9.8 > 40,000 8 - 12 7 - 9 +/- 9.5 +/- 7.5 3,200 8,000 9.4 - 9.8 > 30,000 10 - 14 5 - 7 +/- 9.5 +/- 5 Best Practices: 1 As a standard practice for tie-back string completions, displace the drilling mud above top of liner with brine treated with corrosion inhibitor (Conqor 303A) at a concentration of 1 drum per 100 barrels of fluid. Comments: See mud prognosis for details. Sized CaCOs (SafeCarb) will be used to control leakoff. 6/20/2006 CONFIDENTIAL MATERIAL Page 15 of 19 Susan Dionne #5 Drilling Program 4.17 Solids Control Eauigment • • Marathon Oil Company Northern Business Unit °' a ~ ~, iu ~ o = o ~ Y ~ ~ ~ ~ ~ U ~ ~ y m h ~ N p v ~ o tntervai u O O ~ U U U N Comments 0 - 9,618' MD X X X X Closed Loop System, Full Containment, Run shakers with finest screens possible Item Equipment Specifications (quanfl ,design type, brand, model, flow capacity, etc) Shaker 2 - Swaco Mongoose PT Desander N/A Desilter 1 -Derrick Model 0522 Mud Cleaner N/A Centrifuge 2 - MI/Swaco units Cuttings Dryer N/A Cuttings Injection Marathon G&I Facility Zero Discharge N/A Best Practices: 1 Have vacuum trucks pull fluids from trough above slop pit to more efficiently pull fluids for disposal. This minimizes water added to the solids to suspend for pickup by the trucks, thus minimizing total volume to be disposed of. Comments: 6/20/2006 CONFIDENTIAL MATERIAL Page 16 of 19 Susan Dionne #5 Drilling Program 4.18 Cement Program Summary • • Marathon Oil Company Northern Business Unit De pth Gauge Top of Cement Gauge Ann Vol Slurry Casing Size (in) MD (ft) TVD (ft) Hole Size (in) MD (ft) TVD (ft) Ann Vol To TOC (ft3) With OH Excess (ft3) Density Lead/Tail (ppg) Open Hole Excess (%) Thickening Time (hrs) 20 91 91 Driven N/A 9 5/8 1,623 1,300 12 1/4 0 0 603 997 12.0 75 8 7 4,768 3,200 8 1/2 1,500 1,401 418 595 12.5 / 15.8 40 8 4 1/2 9,618 8,000 7 4,550 3,009 790 1,025 13.0 / 13.0 30 N/A Mix Water Compressive Casing Size Density Qty Yield Sluny Vol TOC MD Qty WL FW Strength (psi} (in) Sluny Cement Description (Ib/gal) (sx} (ft3/sx) (ft3) (ft) (gal/sx) Type (cc) (%} 8 hr 24 hr 9 5/8 Tail Type I Cement 12.0 407 2.45 997 0 10.20 Fresh 547 0 183 675 7 Lead Class"G" 12.5 162 2.47 400 1,500 13.78 Fresh Tail Class "G" 15.8 167 1.17 195 3,768 4.99 Fresh 4 1/2 2nd Stage Class"G" 13.0 254 2.01 510 4,550 10.64 Fresh 1~` Stage Class "G" 13.0 256 2.01 515 7,123 10.64 Fresh Best Practices: 1 Pump several fluid calipers at TD to help with the hole volume determination from the open hole caliper log. 2 A KCL spacer will be utilized and will be sized to 2/3 of the normal volume (20 bbl) to try and minimize the possibility of bridging in the liner lap. 3 A pressure activated cementing valve (DV tool) will be placed in the casing string at approximately 7,123' MD (5,500' TVD). This should be set mid-point TVD of the production liner. This is to ensure that hydrostatic pressure stays below expected frac gradients. Comments: See cement prognosis for details and spacer specifications. 4.19 Res~ulatorv Waivers and Special Procedures Regulation Deviation Comments: 6/20/2006 CONFIDENTIAL MATERIAL Page 17 of 19 Susan Dionne #5 Drilling Program 4.20 Bit Summary • • Marathon Oil Company Northern Business Unit Interval - MD Type Recommended Estimated From (ft) To (ft) Size (in) Manufacturer Model No. IADC WOB kips) RPM Rotating Hours Expected Minimum ROP (ft/hr) 0 1,623 12 1/4 Christensen MXL-1 117 20 - 50 80 - 300 1,623 4,768 8 1/2 Christensen HCM605 M223 Up to 25 Motor 4,768 9,618 4 314 Christensen DOSRWD46.000 M233 3 - 5 100 - 350 Best Practices: 1 Comments: See bit prognosis for additional information. Back up bits for the 8 1/2" hole section will consist of PDC and mill tooth bits. Back up bits for the 7" hole section will consist of 6 1/8" mill tooth and TCI tricone bits. 4.21 Hydraulics Summary Qty Make Model Liner ID (in) Stroke (in) Max Press @ 90% WP (psi} Displacement @ 95% Vol. eff (gal/stroke) Max Rate @ 95% Vol. eff (spm/gpm) Hole Sections Used On 5 8 2,597 2.04 125 / 255 Surface 3 National Oil Well A600PT 5 8 2,597 2.04 125 / 255 Intermediate 5 8 2,597 2.04 125 / 255 Production Est. Hole Pump Standpipe Openhole Nozzle Depth-MD Size Rate Pressure Min AV MW ECD Size AP at bit (ft) (in) (gpm) (psi) (fpm) (ppg) (ppg) (32"s) si Remarks (Drill string confi uration) 3 - 18's 0 - 1,623 12 1/4 600+ 1,600 118 9.4 Actual Data from NS #1 (@ 1,550' MD) 1-16 1,623 - 4,768 8 1/2 500+ 2,150 259 9.4 5 - 15's Actual Data from NS #1 (@ 5,570' MD) 4,768 - 9,618 6 x 7 300+ 2,900 223 9.8 6 - 11's Actual Data from SD #2 (@ 11,094' MD) Best Practices: 1 Comments: 6/20/2006 CONFIDENTIAL MATERIAL Page 18 of 19 Susan Dionne #5 Drilling Program • • Marathon Oil Company Northern Business Unit 4.22 Formation Integrity Test Procedure Surface and Intermediate casing shoes will be tested to Leak-off. Prior to drilling out of casing strings, test BOPs and casing to the specified pressure listed in the BOP Program section. Plot test and record volume required on the drilling report. Leak-off tests (LOT) are to be conducted as described below: 1. Drill 20' to 25' of new formation below the casing shoe and condition the mud to the same properties in and out. 2. Pull drill string into the casing shoe and close ram preventer, and line up to the choke manifold with a closed choke. 3. Begin slowly pumping fluid down the drill string at 1/2 bpm while recording casing and drillpipe pressures at 1/2 bbl intervals. A running plot of pressure versus volume should be kept by the drilling foreman while the test is in progress. 4. Stop pumping when the pressure curve departs form a straight line sufficiently to indicate leakage into the formation. Record as ppg equivalent mud density in the IADC and morning reports. 5. Monitor and plot pressure drop and time after shut-in for 10 minutes or until the shut-in pressure stabilizes. Best Practices: 1 Comments: 6/20/2006 CONFIDENTIAL MATERIAL Page 19 of 19 Marathon Oil Well Susan Dionne #5 Diverter Flow line 21 1/4" 2M Diverter ~ 16" Automatic Knife Valve ~~ Diverter Spool _~ t 16" Diverter Line Marathon Oil Well Susan Dionne #5 BOP Stack Flow Nipple 13 5/8" 5M Annular Preventer -~ 13 5/8" 5M Double Ram Preventer Pipe Ram 2 1/16" 5M Blind Ram Check Valve 2 1/16" 5M Manually Operated Valves ~~ ~LU--~WJLJ~~~--~1J Kill 13 5/8" 5M Cross Pipe Ram 13 5/8" 5M Single Ram Preventer Flow Line Choke X Bottom of Single gate must be 24-45" from ground level for Glacier 1 rig placement. 3 1/8" 5M Manually Operated Valve ~I II Inl II I 1 3 1/8" 5M Hydraulically Operated Valve 13 5/8" 5M x 13 5/8" 5M Drilling Spool 13 5/8" 5M Tubing Head Flange • To Gas Buster X ~ ~~~ ~ x Marathon Oil Well Susan Dionne #5 Choke Manifold To Blooey Line x ~ ~~~ ~ x • Bleed off Line to Shakers x ~ ~~~ ~ x x 1 2 9/16" 10M Swaco Hydraulically Operated Choke From BOP Stack ~~~~ x `°~ ~ ~ 3" 5M Valves X x I 3 1/8" 5M Manually Adjustable Choke • • Surface Use Plan for Ninilchik Unit -Susan Dionne #5 Surface location: 150' FSL, 1,257' FEL, Sec. 6, T1 S, R13W, S.M. 1) Existing Roads The Sterling Highway will be used for access to the Susan Dionne #5 well and is shown on the attached map. Ninilchik, Alaska is the nearest town to the site. 2) Access Roads to be Constructed or Reconstructed No new roads will be required to access Susan Dionne #5. 3) Location of existing wells Well Susan Dionne #5 will be drilled on Susan Dionne pad. A pad drawing is enclosed that shows existing wells and the proposed location of Susan Dionne #5. 4) Location of existing and/or proposed facilities The locations of existing production facilities on the Susan Dionne pad are shown on the enclosed pad drawing. A flowline will be installed from the Susan Dionne #5 wellhead to an existing heater and separator. 5) Location of Water Supply A water supply well exists on the pad that Susan Dionne #5 will be drilled from. This is shown on the pad drawing. 6) Construction Materials No construction is planned on the pad. 7) Methods of handling waste disposal; a) Mud and Cuttings Cuttings will be dewatered on location. The cuttings and excess mud will be hauled to Pad 41-18 of the Kenai Gas Field for disposal into Well KU 24-7, a Class II disposal well (AOGCC Disposal Injection Order No.9, Permit #81-176). b) Garbage All household and approved industrial garbage will be hauled to the Kenai Peninsula Borough Soldotna Landfill. c) Completion Fluids Clear fluids will be hauled to Pad 34-31 of the Kenai Gas field and injected in Well WD #1, an approved disposal well (AOGCC Permit #7-194). d) Chemicals Unused chemicals will be returned to the vendors that provided them. Efforts will be made to minimize the use of all chemicals. • • e) Sewage Sewage will be hauled to the Kenai sanitation facility. 8) Ancillary Facilities A minimal camp will be established on the pad to house various supervisory and service company personnel. Approximately four trailer house type structures will be required for this purpose. Bottled water will be used for human consumption. Potable water will be obtained from the existing water well on the pad. Town & Country will collect and transport sanitary wastes to their ADC approved disposal facility. No additional structures will be necessary. 9) Plans for reclamation of the surface Susan Dionne #5 will be drilled from an existing pad. Reclamation of the pad, if required by the landowner, will occur after the abandonment of Susan Dionne #5 and the other existing wells on the pad. 10) Surface ownership Paul Dionne is the surface owner of the land at the Susan Dionne pad. 11) Operator's Representative and Certification I hereby certify that I, or persons under my direct supervision, have inspected the proposed drill site and access route; that I am familiar with the conditions that currently exist; that the statements made in this plan are, to the best of my knowledge, true and correct; and that the work associated with operations proposed herein will be performed by Marathon Oil Company and its contractors and subcontractors in conformity with this plan and the terms and conditions under which it is approved. This statement is subject to the provisions of 18 U.S.C. 1001 for the filing of a false statement. Date: ~ Z ~ Name and Title: illard J. Tank, dvanced Senior Drilling Engineer Marathon Oil Company P. O. Box 3128 Houston, TX 77253 (713) 296-3277 ~ • ~~,~~ OF A~q --I ~ : Ili `~•. ~ /i ~~49 ~ /, ~ •. M. SCOTT McLANEff ~ ~ 4928-S -- O ~ESS I ONAL `' ~~` '~1\\\\~~1, ~~ G ER 0r I:I~~i O SUSAN DIONNE #3~ SUSAN DIONNE //1 • LEGEND/NOrI'E5 1. BASIS OF HORIZONTAL COORDINATES AND ELEVATIONS IS NGS MONUMENT V82 AT MILE POST 127.8 OF THE STERLING HIGHWAY. THE ELEVATION OF V82 IS 283.59 FEET {NGVD 29). THE HORIZONTAL COORDINATES ARE ALASKA STATE PLANE NAD 27 ZONE 4 AND ARE BASED ON PUBLISHED COORDINATES FROM 1HE STATE OF ALASKA DEPARTMENT OF TRANSPORTATION AND PUBLIC FACILITIES GEOREFERENCING PROJECT PHASE I AND II GPS CONTROL POINTS N 2240672.397E 218213.289. ® NATURAL GAS WELL SURFACE LOCATION U~ TRACTJ 4 DIONNE SID NO. ] P • SUSAN DIONNE #2 ° ° ~ .-~x~ SECTION 6 ~ T15., R13W., S. M., AK PAD SUSAN DIONNE SUSAN DIONNE /~4 J N AwMA wWMIfYRlwO PRORAIY (" SUSAN DIONNE #4 (C[ 1331' FEL 104' FSL SECTION 6 T1 S., R13W., S.M., AK GRID N: 2236587.738 GRID E: 213102.309 LATITUDE: 60'06'46.287"N LONGITUDE: 151'34'21.711 "W ELEV. 135 FT. Consulting Group IV~cLane Testing NORTH CE LOCATION DIAGRAM 1331' FEL vAU AID Busw wwNE PROPFNrv SUSAN DIONNE #5 1257' FEL 150' FSL SECTION 6 T1 S., R13W., S.M., AK GRID N: 2236631.970 GRID E: 213176.667 LATITUDE: 60'06' 46.740"N LONGITUDE: 151'34'20.265"W ELEV. 135 FT. 6 7 TB Ra: "°' °"°'° M Marathon DRAWNO Na: oaTO7• MARAn1oN 0 i I Company N•~• R.yl«~ 1'-100' DRAYM BY: NSM • °itlN~R A°°R°"AL SUSAN DIONNE PAD NINILCHIK, ALASKA P~°* ~ SUSAN DIONNE N0. 4 & 5 AS-BUILT : SURFACE LOCATIONS ~T, scuE DvnL ... DATE +~roro~ FlLE Na axs "aD wsc svsT DwD Na nEv I" CNN0. DATE .•ru 1'.1 ~o•_ nix S 0 00 0 00 OOw 1 0 Marathon Oil Company Project: Susan Dionne No. 5 N.ase :_I~r:_ ~ . SW '/~, SE '/+, 6, T1S, R13W Seward 1Vleridian , Project Location x,15 4 ~ p 1. ~~ - ~~ 1= ~- ,, _I_ ~„~ 1? °:° ' .~~~ i J ~~o% i 18 r/ _ a __I¢ IQ Y 3 ~°''~. Jackinxky Ranch ° Nin~lth~k NO J 1 • ~~ cY 1 +- ^Y Q ~ ~ ~ 4', y Aso , 1 ~,. i , 3Q~~• ~ 28 ~7 1 -+ - p' °,y -- 1 -- -.. -. -- i 1 1 1 '- -r Ninilchlk~ ~_ __ I I ' ° o Nrg ~ I ~;; ...rl -sr, 35 _:~; ~ 31 i 3. 33 3G I:.. p,l I i34 1 '~~ •. 1 ., ~ 1 ., I , __, 1 _ ~~ ~ °~- 1 ~ Cape Nmikhik i ~ .: ,. °°~ N 1: ` NInUCMM ~ ~ .. ~~aas.- ~ ~I um,n~ $1 d: ,, I \~1 ,~~~ > °i0 11 any. !; % - .. 0'9 10 .. ~°4 M y1~. . .~n~. ~ , N~V 76L~ ~ ~ '66530a ~. i ~'! ~ ~ 1~1 A~ I.~ lg 17 16 15 N'i Y ~ i ' I 1SE DOVIA D-Sl 40 ~ - - i a Li ti __ _- '_-~5, • o „' 7582~"m E. __ -t51°3Q 00 KENAI (A-5) ~UADRANCLE ALASKA-KENAI PENWSULA BOROUGH i SCALE 163360 1:63360 SERIES (TOPOGRAPHIC) ~ ~-% -r ~' 1 ------~ . _ s o Macs ._ ~ - ~. - 3000 0 3000 6000 ---9000 !7000 15000 19000 71000 EEET Env'-F_?-T-"~7--.~~'r-- .- - 1 - 0 7 3 0 5 RIlOME7ER$ • • Susan Dionne 5 Location 03/2006 GLACIER DRILLING RIG #1 MUD PITS AND PUMP ROOM LAYOUT ,~~ m= a ~ ~~ ~~ ~ ~ om ~3 0 U ._ O~ C Z ~~ a O m ZY ro Q am m lL Cy_ y L Q U Z .s` m lL O J .T. 4 .N W QC a ~. ~ ~~~~~ ~ '~ ~ ~ ~ a 8 o ~~ ~ ~ ~ ~ $ ~° ~ m ~ ~ $ ~ ~ N QOap `R s~ N ~ $ RRi~' v ooua - wv ~ .nos (ll) 43daa ie~~an anal 8 ~ ~ ' ~ ~ ~ a i ~7 ~~ 3 Q W v8 sZ g~$ RR ~ ~~ >; m O Northing (ft) M MARATHON Planned Wellpath Report SD#5 Ver 2 Page 1 of 7 ~~.~ BAKER MYl~NEi INTEQ Operator MARATHON Oil Company .Slot SD#5 Area Cook Inlet, Alaska (Kenai Penninsula) Well SD#5 Field Ninilchik Field Wellbore SD#5 Ver 2 :Facility Susan Dionne . ~ ~ !Projection System ~ NAD27 / TM Alaska State Plane, Zone 4 (5004), US feet Software System We1lArchitectTM 1.2 North Reference True User Suthstud Scale . 0.999994 'Report Generated 05/25/06 at 14:28:51 Wellbore last revised 03/22/06 Database/Source file WA-Anchorage/SD#5_Ver_2.xm1 ~ 1 Local coordinates Grid coordinates Geographic coordinates North [feet] East [feet] Fasting [US feet] Northing [US feet] Latitude [°] Longitude [°] Slot Location 242.07 -1265.93 213176.67 2236631.97 60 06 46.740N 151 34 20.265W Facility Reference Pt 214436.50 2236359.99 60 06 44.356N 151 33 55.287W Field Reference Pt 226657.85 2252005.12 60 09 21.189N 151 30 01.220W _J Calculation method Minimum curvature Glacier 1 (RKB) to Facility Vertical Datum 156.00 feet Horizontal Reference Pt Slot Glacier 1 (RICH) to Mean Sea Level 156.00 feet Vertical Reference Pt Glacier 1 (RKB) Facility Vertical Datum to Mud Line (Facility) 0.00 feet MD Reference Pt Glacier 1(ItKB) Section Origin N 0.00,E 0.00 ft Field Vertical Reference Mean Sea Level Section Azimuth 220.69° MARATHON Planned Wellpath Report SD#5 Ver 2 Page 2 of 7 r~.~ BAKER N1~61~IES INTEQ Operator ,. ~ __ - __ _ _ _ _ , MARATHON Oil Company „Slot `SD#5 Area Cook Inlet, Alaska (Kenai Penninsula) Well SD#5 Field Ninilchik Field Wellbore SD#5 Ver 2 Facility Susan Dionne ~WELLPATH DATA (103 stations) ~ =inter polated/extra polated station MD Inclination Azimuth TVD Vert Sect North East Grid East Grid North DLS ath [feet] [°] [°] [feet] [feet] [feet] [feet] (us surve feet] [us survey feet] [°/100ft] Comment 0.00 0.000 220.689 0.00 0.00 0.00 0.00 213176.67 2236631.97 0.00 100.00' 0.000 0.000 100.00 0.00 0.00 0.00 213176.67 2236631.97 0.00 200.00 0.000 220.689 200.00 0.00 0.00 0.00 213176.67 2236631.97 0.00 300.00' 5.000 220.689 299.87 4.36 -3.31 -2.84 213173.75 2236628.73 5.00 400 00' 10 000 220 689 398 99 17 41 13 20 1 35 2 . . . . ~ . - . - 1. 13165.01 2236619.04 500.00', 15.000 220.689 496.58 39.05 ; -29.61 -25.46 213150.51 2236602.98 5.00 600.00' 20.000 220.689 _ 591.93 69.11 -52.40 -45.05 213130.38 2236580.66 ~ _ 5.00 700.00' 25.000 _ 220.689 684.28 __ 107.36 -81.41 -70.00 213104.75 2236552.25 5.00 800.OOj~ 30.000 220.689] 772.96 153.52 ~ -116.41 -100.09 ', 213073.84 2236517.98 5.00 900. ~ 35 000 220 6 9 857 27 207 24 157 14 3 ~ ., ' . . 8 . _ _ . - . _ -1 5.11 213037.86 2236478.09 5.00 1000.00' 40.000 v 220.689, _ 936.58 ~ 268.09 , -203.28 -174.79 i 212997.10 2236432.90 5.00 1100.00' 45.000 _ 220.689 1010.28 _ 335.63 -254.49 _ -218.82 ~tl 212951.86 2236382.76 5.00 1200.00' 50.000 220.689 1077.82 409.34 -310.38 -266.87 212902.49 2236328.03 5.00 1300.OOt 55.000 220.689 1138.68 488.65 -370.52 -318.58 212849.37 i 2236269.14 5.00 ; 1400 OO 60 000 220 689 1192 39 572 96' 434 45 3 3 2 . t . . ; . . - . - 7 .54 12792.90 ~ 2236206.54 5.00 i 1425.29 61.264 220.689 1204.79 594.99 ! -451.16 -387.91 212778.14 ~ 2236190.17 5.00 1500.00' 61.264 220.689 1240.71 660.51 -500.83 -430.62 212734.25 2236141.53 0.00 1600.OOt 61.264 220.689 1288.79 748.19 -567.32 -487.79 212675.52 2236076.42 0.00 1700.00 61.264 220.689 1336.87 835.88 -633.81 544.96 21261.6.79 2236011.31 0.00 ' ` 1800 0 " ~ 264 ° 220 689 1384 4 ` )23 i 00 '' ~ ~ ' . r ..:61. . .9 ~ x ., ~., -7 .29 602.12 ~ 21255$°„ 2235946.20 #u£ 1900.00]' 61.264 220.689 1433.02 1011.25 -766.78 ~ ___ 659.29 , 212499.33 2235881.10 ~ 0.00 2000.00 fi 61.264 220.689 1481.10 1098.93 -833.27 -716.46 ~ 212440.60 2235815.99 0.00 2100.OOj~ 61.264 220.689 1529.17 1186.61 -899.76 -773.62 212381.86 2235750.88 0.00 2200.00' 61.264 220.689 1577.25 1274.30 -966.24 -830.79 212323.13 2235685.77 0.00 MARATHON Planned Wellpath Report SD#5 Ver 2 Page 3 of 7 r~~~ BAKER I~IV6MES INTEQ Operator ,. ~ ~ MARATHON Oil Company Slot SD#5 Area Cook Inlet, Alaska (Kenai Penninsula) Well SD#5 Field Ninilchik Field Wellbore SD#5 Ver 2 Facility Susan Dionne LPATH DATA (103 stations) fi = interpolated/extrapolated station 1ID Feet] Inclination [°] Azimuth [°] TVD [feet] Vert Sect (feet] North [feet] 2400.00 61.264 220.689 1673.41 1449.67 -1099.22 2500.OOfi 61.264 220.689 1721.48 1537.35 -1165.71 2600.OOt 61.264 220.689 1769.56 1625.04 -1232.19 2700.OOt 61.264 220.689 1817.64 1712.72 j -1298.68 2800.OOj'; 61.264 220.689 1865.71 1800.41 I -1365.17 2900.OOt 61.264 220.689 1913.79 1888.09 -1431.66 3000.OOj~ 61.264 220.689 1961.87 ~ 1975.78 -1498.14 3054.40 61.264 220.689 1988.02 2023.47 -1534.31 3100.OOt 60.352 220.689 2010.26 2063.29 -1564.50 -- - 3200.OOj' S8.352~ _ _ 220.689 __ 2061.23 ~ _ 2149.31 ; _ -- - -1629.73 3300.OOt 56.352 220.689 2115.18 2233.51 -1693.57 3400.00' 54.352 220.689 2172.03 2315.77 -1755.95 3500.00' 52.352 220.689 2231.72 2396.00 -1816.78 3600.00 50.352 220.689; 2294.17 2474.10 -1876.00 3700.00'x, _ 220.6891 2359.30 _ 2549.96 _ -1933.52 3800.00' 46.352 220.689 2427.05 2623.51 -1989.29 3900.OOt 44.352 220.689 2497.32 2694.65 -2043.24 4000.00 j' 42.352 220.689 2570.03 2763.30 -2095.29 4100.OOfi 4200.U0~ 40.352 Y..,;, 220.689 -w"~ 220.689 2645.09 2829.36 ---_-2722.41 ;~ 2892.77 -2145.38 -2193.46 4300.00' 36.352 220.689 2801.90 295 3.44 -2239.46 4400.OOt 34.352 220.689 2883.46 _ 3011.2 9 -2283.33 4500.00' 32.352 220.689 2966.99 _ _ C 3066.27 _ -2325.02 4600.OOt 30.352 220.689 3052.38 3118.30 -2364.47 East [feet] Grid East (us survey feet] Grid North [us survey feet] DLS [°/100ft] -945.12 212205.67 2235555.56 0.00 -1002.29 212146.94 2235490.45 0.00 -1059.46 212088.20 2235425.34 0.00 -1116.62 212029.47 2235360.23 0.00 -1173.79 211970.74 2235295.12 0.00 -1230.96 211912.01 2235230.02 0.00 -1288.12 211853.28 2235164.91 0.00 -1319.22 211821.33 2235129.49 0.00 -1345.17 211794.66 2235099.93 2.00 -1401.2b;: 211737.04 2235036.05 2.00 -1456.15 211680.65 2234973.54 2.00 -1509.78 211625.55 2234412.46 2.00 -1562.09 211571.81 2234852.88 2.00 -1613.01 211519.50 2234794.90 2.00 -1662.4~~. ., .,: , 211468.68- 2234738.56 2.00 -1710.42 211419.42 2234683.95 2.00 -1756.80 211371.77 2234631.13 2.00 -1801.55 211325.79 2234580.16 2.00 -1844.63 -1885.96 211281.54 211239..07 2234531.10 ,;~ 2234 2.00 . r`',`2.00 -1925.52 211198.43 2234438.97 2.00 -1963.24 211159.68 2234396.01 __2.00 -1999.08 211122.86 2234355.19 2.00 -2033.00 211088.01 2234316.56 2.00 MARATHON Planned Wellpath Report SD#5 Ver 2 Page 4 of 7 r~.~ BAKER 1~11~6M ES INTEQ Operator ~. ~ ~ MARATHON Oil Company Slot SD#5 Area Cook Inlet, Alaska (Kenai Penninsula) Well SD#5 Field Ninilchik Field Wellbore SD#5 Ver 2 Facility Susan Dionne ,LPATH DATA (103 s tations) fi =interpolated / extrapolate d station MD Inclination Azimuth TVD Vert Sect North East Grid East Grid North DLS [feet] [°] [°] [feet] [feet] [feet] [feet] [us survey feet] [us survey feet] [°/100ft] 4800.00 26.352 220.689 3228.35 3213.26 -2436.47 -2094.91 211024.40 2234246.05 2.00 4900.00' 24.352 220.689 3318.72 3256.07 -2468.93 -2122.82 210995.73 2234214.26 2.00 5000.00 22.352 220.689 3410.52 3295.71 -2498.99 -2148.66 210969.18 2234184.83 2.00 5100.001' 20.352 _ 220.689 3503.65 3332.12 -2526.60 _ j -2172.40 210944.79 2234157.79 2.00 S 155 64 19 240 220 689 3556 00 3350 96 2540 88 2184 68 ' 2 09 ' . . . i . . - . - . ~ 1 32.17 2234143.80 2.00 5200.001' 18.352 220.689 3598.00 3365.25 -2551.72 i -2194.00 210922.60 2234133.19 2.00 5300.001' 16.352 220.689 3693.44 _ 3395.08 -2574.33 -2213.45 210902.62 2234111.05 2.00 5400.001' 14.352 220.689 3789.87 3421.55 -2594.41 -2230.71 210884.89 2234091.39 2.00 5500.001' 5600 00 ' 12.352' 10 352 220.689 220 689 3887.16 3985 20 ~ 3444.64 , 3464 3 -2611.92 26 6 -2245.76 210869.42. 2234074.24 2.00 . 1 . . .3 - 2 .84 -2258.59 ~ 210$56.24 2234059.63 2.00 5700.00 8.352 220 689 _ 4083.87 ~ 3480.57 -2639.16 -2269.19 210845.35 2234047.56 2.00 5800.00 6.352 220.689 4183.04 3493.37 _ -2648.87 __ _ _ -2277.53 210836.78 2234038.06 2.00 5900.OOt 4.352 220.689 4282.60 3502.70 -2655.94 -2283.61 210830.53 2234031.13 2.00 6000.00 2.352 220.689 4382.42 3508.55 , -2660.37 -2287.42 210826.62 2234026.79 2.00 6100:001 352 0 220 6891 4482 39 3510 91 2662 16 2288 96 2 _ ' . . . j . - . - . 10825.04 2234025.04 2.00 6117.61 0.000 220.689 4500.00 3510.96 -2662.20 -2289.00 210825.00 2234025.00 2.00 6200.00 0.000 0.00 0 4582.39 3510.96 -2662.20 -2289.00 210825.00 2234025.00 0.00 6300.00 0.000 0.000 4682.39 3510.96 -2662.20 -2289.00 210825.00 2234025.00 0.00 6400.001' 6500 00' 0.000 O 000I ~ 0.000' -----`0 004 4782.39 2 39' 351.0.96 3S1U: `` -2662.20 2662 20 "` -2289.00 2289 00 i 210825.00 2 2234025.00 ` `2 0.00 ` . . . ; ;~~8 . , . - .- . 10$2~,m . 234025.00 _ 6600.00' 0.000 0.000 4982.39 3510.96 -2662.20 i -2289.00 210825.00 2234025.00 0.00 6700.00f 0.000 0.000 5082.39 _ 3510.96 -2662.20 -2289.00 210825.00 2234025.00 0.00 6800.001' 0.000 0.000 5182.39 3510.96 -2662.20 -2289.00 210825.00 2234025.00 0.00 6900.001' 0.000 0.000 5282.39 3510.96 -2662.20 -2289.00 210825.00 2234025.00 0.00 M MARATHON Planned Wellpath Report SD#5 Ver 2 Page 5 of 7 r~.~ BAKER I~IY6MES INTEQ Operator ,. ~ ~ MARATHON Oil Company Slot SD#5 Area Cook Inlet, Alaska (Kenai Penninsula) Well SD#5 Field Ninilchik Field Wellbore SD#5 Ver 2 Facility Susan Dionne LPATH D ATA (103 stat ions) t = int erpolated/ext rapolated s tation NID Iucliuatiou Azimuth TVD Vert Sect North East Grid East Grid North DLS :'feet) [°] [°] [feet] [feet] [feet] [feet] [us survey feet] [us survey feet] [°/100ft] 7100.00' 0.000 0.000 5482.39 3510.96 -2662.20 -2289.00 210825.00 2234025.00 0.00 7200.00' 0.000 0.000 5582.39 3510.96 -2662.20 -2289.00 210825.00 2234025.00 0.00 7300.00 0.000 0.000 5682.39 3510.96 -2662.20 ; -2289.00 a 210825.00 2234025.00 0.00 7338.61 0.000 220.689 5721.001 3510.96 ~ -2662.20 -2289.00 210825.00 2234025.00 0.00 7400.00 0.000 0.000 5782.39 3510.96 _ _-_2662.20 v __-2289.00_ 210825.00 2234 025.00 0.00 7500.OOtj 0.000 0.000 5882.39 3510.96 -2662.20 ~ -2289.00 ~ 210825.00 j _ _ 2234025.00 0.00 7600.00 0.000 0.000 5982.39 3510.96 -2662.20 -2289.00 210825.00 2234025.00 0.00 7700.00 j' 0.000 0.000 6082.39 3510.96 -2662.20 -2289.00 210825.00 2234025.00 0.00 _7800.00 j' __ 0.000 _ 0.000_ ~_______ __ _ _6182.39 _ 3510.96 '~ -2662.20 289.00 2 _ 210825.00 ~ ~ 2234025.00 0.00 7900 0¢' 0 000 0 000 6282 39 3510 96 - -- - - 2662 -- 20 _ 89 0 ~ --_ _...._. ____ _ __~ __ ~O . . ~ . ~ . . . - . . ~2 0 210825.00 2234025.00 O.f 8000.OOt 0.000, 0.000 6382.39 3510.96 -2662.20 -2289.00 2108 2 5.00 223 4 02 5 . 00 0.00 8100.OOt 0.000 0.000 __ 6482.39 ___ 3510.96 _ __ ~ -2662.20 -2289.00 ______ _ _ i 210825.00 _ _ . . _ _ 2234025.00 0.00 8200.OOfi 0.000 0.000 6582.39 3510.96 -2662.20 -2289.00 210825.00 2234025.00 0.00 8300.OOt 0.000 0.000 6682.39 3510.96 -2662.20 -2289.00 -~~ 210825.00 2234025.00 0.00 8400 04` 0 0 000 ~82 39 ~ 3510 96 ~ ~ 2 20 ~ 2289 0 2 ~ _~_- 02 _ . . . ~ ~ . . ' . _ : .,8 . _ - . 0 10825.00 2234 5.00 0.00 8500.OOt~ 0.000 0.000 6882.39 ~ 3510.96 I -2662.20 , -2289.00 210825.00 __ _ 2234025.00 0.00 8600.00' 0.000 0.000 6982.39 3510.96 -2662.20 -2289.00 210825.00 2234025.00 0.00 8700.00 0.000 0.000 7082.39 3510.96 -2662.20 -2289.00 210825.00 2234025.00 0.00 8800.00 0.000 0.000 7182.39 3510.96 -2662.20 -2289.00 210825.00 2234025.00 0.00 8900 OQ ~ 0 000 0 000 7282 39 ' 3510 96 2662 20 '' 2 00 N " k 4 ~'~ ~ . . : .; . . ~,~ . - . . ~2 89. = 210825.. 2234025. 0 4 nY 9000.00' 0.000 0.000 7382.39 3510.96 -2662.20 -2289.00 210825.00 2234025.00 0.00 9100.OOj' 0.000 0.000 7482.39 3510.96 -2662.20 -2289.00 _ _ _ 210825.00 2234025.00 0.00 9200.OOt 0.000 0.000 7582.39 3510.96 -2662.20 -2289.00 210825.00 2234025.00 0.00 9300.00' 0.000 0.000 7682.39 3510.96 -2662.20 -2289.00 210825.00 2234025.00 0.00 MARATHON Planned Wellpath Report SD#5 Ver 2 Page 6 of 7 r~.~ BAKER 1~11~6NES INTEQ Operator .. ~ ~ MARATHON Oil Company Slot SD#5 Area Cook Inlet, Alaska (Kenai Penninsula) Well SD#5 Field Ninilchik Field Wellbore SD#5 Ver 2 Facility Susan Dionne ELLPATH DATA (103 stations) ~' = interpolated/extrapolated s tation MD [feet] Inclination [°] Azimuth [°] TVD [feet] Vert Sect [feet] North [feet] East [feet] Grid East [us survey feet] Grid North [us survey feet] DLS [°/100ft] ath Comment 9500.00 0.000 0.000 7882.39 3510.96 -2662.20 -2289.00 210825.00 2234025.00 0.00 9600.00 j' 0.000 0.000 7982.39 3510.96 -2662.20 ~ -2289.00 210825.00 2234025.00 0.00 9617.61 0.000 220.689 8000.002 3510.96 ~ - -2662.20 -2289.00' 210825.00 2234025.00 0.00 HOLE & CASING SECTIONS Ref Wellbore: SD#5 Ver 2 Ref Wellpath: SD#5 Ver 2 String/Diameter Start MD [feet] End MD [feet] Interval [feet] Start TVD [feet] End TVD [feet] Start N/S [feet] Start E/W [feet] End N/S [feet] End E/W [feet] 9.625in Casing Surface 0.00 1623.32 1623.32 0.00 1300.00 0.00 0.00 -582.82 -501.12 Tin Casing Intennediate 0.00 4768.27 4768.27 0.00 3200.00 0.00 0.00 -2425.67 -2085.62 4.Sin Liner 4768.27 9617.60 4849.33 3200.00 7999.99 -2425.67 -2085.62 -2662.20 -2289.00 12.25in Open Hole 0.00 1623.32 1623.32 0.00 1300.00 0.00 0.00 -582.82 -501.12 8.Sin Open Hole 1623.32 4768.27 3144.95 1300.00 3200.00 -582.82 -501.12 -2425.67 -2085.62 Tin Open Hole 4768.27 9617.60 4849.33 3200.00 7999.99 -2425.67 -2085.62 -2662.20 -2289.0 _J MARATHON Planned Wellpath Report SD#5 Ver 2 Page 7 of 7 INTEQ Operator ~. ~ ~ MARATHON Oil Company Slot SD#5 Area Cook Inlet, Alaska (Kenai Penninsula) Well SD#5 Field Ninilchik Field Wellbore SD#5 Ver 2 Facility Susan Dionne TARGETS Name MD [feet] TVD [feet] North [feet] East [feet] Grid East [us survey feet] Grid North [us survey feet] Latitude [°] Longitude [°] Shape 3483.00 -2662.20 -2289.00 210825.00 2234025.00 60 06 20.519N 151 35 05.419W circle SD#5 Tyonek Tgt - 4/27/06 4123.00 -2662.20 -2289.00 210825.00 2234025.00 60 06 20.519N 151 35 05.419W circle SD#5 T2 Tgt - 4/27/06 7338.61 5721.00 -2662.20 -2289.00 210825.00 2234025.00 60 06 20.519N 151 35 05.419W i circle 1) SD#5 T3 Tgt - 3/22/06 9617.61 -~ .:.; v :.~, _ .a ..,. . r.~ circle 2) SD#5 TD Tgt - 4/27/06 Start MD I End MD Positional Uncertainty Model Log Wellbore ] 0.001 9617.61 ~1aviTrak (Standard) I ISD#5 Ver 2 ~ M MARATHON Oil Company Locatbn: Cook Inlet, Alaska (Kenai Pennlnaula) Sbt: SDMS MARATHON Field: Ninpchlk Flea Well: SosS ~, . ~, n Easting (ft) -zaoo -zzoo -soon -teoo -teao -taco -tzoo -tooo •eoo -eoo eao -zoo S~~ ~ •g ~ ~ ~- ~~~~ ~~ r~ ~~ BAKER H116FIE5 INTEQ aoo z~ 0 Z a s rarr.o,...m..o..w. r~. wd apr..n .w.se r m. r Ppl or Mwr w~nn r it era r. vrr., mr ~ u rr rr....e eye..~..w..m r arrr r {wad ram wr«.~c« m. ,var i lr1Ne1 m u..r~ sr r...c ne ti _ u.n s.. ~ b re ti Ivray - s.u~ m..k a ti o.om..~ _ Gwebw v. F 1..1 rMr~eaE b 9e1 ' G.tleE M'- ~tl.b0 m dYeYO/ MARATHON 600 4 • • MARATHON Oil Company Locatbn: Cook Inlet, Alaska (Kesel Pennlnsula) Sbt: SDN5 Flekt: Ninilchik Fisk1 Well: SD#5 Fa ili uses D' ellbore: Dp Ver ra ~w..o ..q.n . oe yr , Tiu v~ud eW~ w nr~oa b urar , ob ere.,. HNTI ~ n um sir rry m.. (~} u ar Ylrvtl OgYe w leeev! b OsYr 1 Qp) .... - 'IMF IbMrcr T„e „su ffrYl 1 la®1 b YYen Br lin! d Irl dY Tv aa,s Mr, Br lwV b lee M ffe~' - am GYeeR 0 be eiVee w h Ne meet w n br iVeeeW b m cm.a . wa,m m erre0oe All Depths shown are Measured Depths on Reference Well Traveling Cylinder: Map North .~ ~° 0' raarr 330 0 / I 30 r4orr 6 0 0 r2orr 800 30 0 0 room eorr 200 -800 eorr 600 4orr eorr 600 20rr ' l ~ j' . r_ 1-~- __ I ' I " 400 r ~ 7 ~ -~_~_~- i ~ . ;'.. ~ j i / ~ 40It )~~ i i ,~ BOrt / ~~ , \ i, {~ % ~; e0rt ` i % / ~ i `/ '• ,'~ ~ ~~~~ \ t00rt 120/r 140rt iB0/t 210' 150' reotr e~.i. , tion . w R 18 0' M MARATHON Clearance Report Closest Approach SD#5 Ver 2 Page 1 of 11 r~rr BAKER 1~IY6NES INTEQ Operator MARATHON Oil Company Slot SD#5 :Area Cook Inlet, Alaska (Kenai Penninsula) Well SD#5 'Field Ninilchik Field Wellbore SD#5 Ver 2 Facility Susan Dionne / TM Alaska State Plane, Zone 4 (5004), US feet ellArchitectT"' 1.2 North Reference True User Suthstud Scale 0.999994 Report Generated 5/25/2006 at 14:24:23 Wellbore last revised 3/22/2006 Database/Source file WA-Anchoraee/SD#5 Ver 2.xm1 ~, ~ Local coordinates Grid coordinates Geographic coordinates North [feet] East [feet] Easting [US feet] Northing [US feet] Latitude [°] Longitude [°] Slot Location 242.07 -1265.93 213176.67 2236631.97 60 06 46.740N 151 34 20.265W Facility Reference Pt 214436.50 2236359.99 60 06 44.356N 151 33 55.287W 'Field Reference Pt 226657.85 2252005.12 60 09 21.189N 151 30 01.220W ~, Calculation method Minimum Curvature ' Glacier 1 (RKB) to Facility Vertical Datum 156.00 feet Horizontal Reference Pt Slot Glacier 1 (RKB) to Mean Sea Level .. 156.00 feet Vertical Reference Pt Glacier 1 (RKB) Facility Vertical Datum to Mud Line (Facility) 0.00 feet MD Reference Pt Glacier 1 (RKB) 'Field Vertical Reference Mean Sea Level POSITIONAL UNCERTAINTY CALCULATION SETTINGS Ellipse Confidence Limit 3.00 Std Dev Ellipse Start Depth 0.00 feet Surface Position Uncertainty included `Declination 19.57° East of TN Dip Angle 73.01° Magnetic Field Strength 55218 nT M wu-w-Txox Clearance Report Closest Approach SD#5 Ver 2 Page 2 of 11 ~~^ BAKER _NUaN~s INTEQ s ~ww. _~~ . .u W -ANTI-COLLISION RULE Rule Name E-type Closest Approach w/Hole&Csg Limit:0 StdDev:3.00 w/Surface Uncert Rule Based On Ellipsoid Separation'. Plane of Rule Closest Approach Threshold Value 0.00 feet Subtract Casing & Hole Size yes Apply Cone of Safety no ~~x.~. ..„. ~ ~. ~ - . _ ,. , ., r • ~ .,., HOLE & CASING SECTIONS Ref Wellbore: SD#5 Ver 2 Ref Wellpath: SD#5 Ver 2 String/Diameter Start MD (feet] End MD [feet] Interval [feet] Start TVD [feet] End TVD [feet] Start N/S [feet] Start E/W (feet] End N/S [feet] End E/W [feet] 9.625in Casing Surface 0.00 1623.32 1623.32 0.00 1300.00 0.00 0.00 -582.82 -501.12 .7in Casing Intermediate 0.00 4768.27 4768.27 0.00. 3200.00 0.00 0.00' -2425.67.. -2085.62 4.Sin Liner 4768.27. 9617.60 4849.33 3200.00: 7999.99 -2425.67 -2085.62' -2662.20 -2289.00 12.25in Open Hole 0.00 1623.32 1623.32 0.00 1300.00 0.00 0.00 -582.82 -501.12 8.Sin Open Hole 1623.32 4768.27 3144.95. 1300.00 3200.00 -582.82 -501.12 -2425.67 -2085.62 7in Open Hole 4768.27 9617.60 4849.33' 3200.00 7999.99 -2425.67 -2085.62 -2662.20 -2289.00 ~~ SURVEY PROGRAM Ref Wellbore: SD#5 Ver 2 .Ref Well ath: SD#5 Ver 2 __ Start MD End MD Positional Uncertainty Model Log Name/Comment Wellbore feet [feet] i 0.00 9617.61 aviTrak (Standard) SD#5 Ver 2 M MARATRON Clearance Report Closest Approach SD#5 Ver 2 Page 3 of 11 ~~~ BAKER ~IY6NES INTEQ Operator MARATHON Oil Company Slot SD#5 Area Cook Inlet, Alaska (Kenai Penninsula) Well SD#5 Field Ninilchik Field Wellbore SD#5 Ver 2 Facility Susan Dionne CALCULATION RANGE & CUTOFF From: 0.00 MD To: 9617.61 MD C-C Cutoff: 500.00 feet .. ,... !OFFSET WELL CLEARANCE SUMMARY (4 Offset Wellpaths selected) Offset Offset Offset Offset Offset Ref Facility Slot Well Wellbore Wellpath MD [feet] Min C-C Diverging Ref MD of Min C-C Min C-C Clear Dist from MD Min C-C EII Sep EII Sep [feet] [feet] EII Sep [feet] Dvrg from IfP.P.Y~ ~rPP*~ ACR Status Susan Dionne SD #1 SD #1 SD #1 MSS <2498-14931'> 805.40 171.37 805.40 805.40 150.14 805.40 PASS Susan Dionne SD #2 SD #2 SD #2 MWD <0-11094> 137.38 175.47 137.38 137.38 162.54 137.38. PASS Susan Dionne SD #3 SD #3 SD #3 MWD <0-10255> 0.00 207.19 400.00 400.00 190.78 400.00 PASS Susan Dionne SD #4 SD #4 SD #4 MWD <0-11953> 341.40 84.40 341.40 357.28 70.81 357.28 PASS • MARATHON Clearance Report Closest Approach SD#5 Ver 2 Page 4 of 11 CLEARANCE DATA -Offset Wellbore: SD #1 Offset Wellpath: MSS <2498-14931'> Facility: Susan Dionne Slot: SD #1 Well: SD #1 Threshold Value=0.00 feet fi =interpolated/extrapolated station r~~r. BAKER _ Nu6NEs INTEQ Ref MD Ref TVD Ref North Ref East Offset MD Offset TVD Offset North Offset East Horiz Bearing C-C Clear Dist Ellipse Sep ACR MASD ACR feet] [feet] [feet] [feet] [feet] [feet] [feet] [feet] [° feet [feet] [feet] Status 0.00 0.00 0.00 0.00 0.00 3.00 -6.48 -231.58 268.40 231.69 218.78 12.91 PASS 100.001 100.00 0.00 0.00 97.00 100.01 -6.48 -231.58 268.40 231.67 218.30 13.37 PASS 200.00 200.00 0.00 0.00 197.00 200.01 -6.48 -231.58 268.40 231.67 217.81 13.85 PASS 300.001 299.87 -3.31 -2.84 296.87 299.88 -6.48 -231.58 269.21 228.75 213.91 14.84 PASS 400.001 398.99 -13.20; -11.35 395.99 398.99 -6.48 -231.58 271.75 220.33 203.56 ~ _ 16.77 PASS 800.001 496.58 -29.61 -25.46 493.58 496.59 -6.48 -231.58 276.40 207.41, 189.39 18.02 PASS 600.001 591.93 -52.40 -45.05 588.93 591.93 -6.48 -231.58 283.83 192.09 172.89 19.21 PASS 700.001 684.28 -81.41 -70.00 681.28 684.29 -6.48 -231.58 294.88 178.11 157.84 20.27 PASS 800.001 772.96 -116.41 -100.09 769.96 772.96 -6.48 -231.58 309.90 171.39, ___ 150.21 21.17 PASS 8t?~~,~ ~ 777.63 -11$.47 -101.$6 ° ' `' ~~'4,13 777.13 ~ -6.48 5 ~1:~8 310.80 ° ; 171 37~ • _ 1~ ---- ~~;r< 21.23 -- PASS 900.001 857.27 -157.14 -135.11 854.27 857.28 -6.48 231.58 _ 327.37 178.90 _ 156.74 22.15 PASS 1000.001 936.58 -203.28 -174.79 933.58 936.59 -6.48 -231.58 343.90 204.83 181.18 23.65 PASS 1100.001 1010.28 -254.49; -218.82 1007.28 1010.29 -6.48 -231.58 357.06 248.34 223.14 25.20 PASS 1200.OOfi 1077.82 -310.38 -266.87 1074.82 1077.83 -6.48 -231.58 6.62 305.94 279.28 26.67 PASS 1300.001; 1138.68 -370.52 -318.58 1135.68 1138.6$ -6.48 -231.58 13.44 - ~ 374.29 346.48 27.81 PASS 1400.001, 1192.39 -434.45 -373.54 1189.39 1192.40 -6.48 -231.58 18.35 450.90 422.21 28.69 PASS 1425.29 1204.79 -451.16 -387.91 1201.79 1204.80 -6.48 -231.58 19.37 471.36 442.48 28.88 PASS C-C Clearance Distance Cutoff: 500.00 feet M MARATHON Clearance Report Closest Approach SD#5 Ver 2 Page 5 of 11 ~~~ BAKER 1~IY6l~IES INTEQ ::Operator ,__ ~ MARATHON Oil Company Slot SD#5 Area Cook Inlet, Alaska (Kenai Penninsula) Well SD#5 Field Ninilchik Field Wellbore SD#5 Ver 2 Facility Susan Dionne ,. ,x, , - WELLPATH COMPOSITION Offset Wellbore: SD #1 Offset Wellpath: MSS <249R-14931 ~> Start MD feet End MD [feet] Positional Uncertainty Model Log Name/Comment Wellbore 0.00 14930.50 Photomechanical Ma netic (Standard) MSS <2498-14931> SD #1 3.. a. .. aT,_ . ,.r~.~. ,_ ~. ~ ~. OFFSET WELLPATH MD REFERENCE -Offset Wellbore: SD #1 Offset Wellpath: MSS <2498-14931'> MD Reference: Glacier #1 (RKB) Offset TVD & local coordinates use Reference Wellpath settings (See WELLPATH DATUM on page 1 of this report) M MARATHON Clearance Report Closest Approach SD#5 Ver 2 Page 6 of 11 r~.r BAKE R Nu6NEs INTEQ Operator ,. ~ ~ MARATHON Oil Company Slot SD#5 Area Cook Inlet, Alaska (Kenai Penninsula) Well SD#5 Field Ninilchik Field Wellbore SD#5 Ver 2 Facility Susan Dionne DATA -Offset Wellbore: SD #2 Offset Wellpath: MWD <0-11094> ±acility: Susan Dionne Slot: SD #2 Well: SD #2 Threshold Value=0.00 feet ~' =interpolated/extrapolated station Ref MD Ref TVD Ref North Ref East Offset MD Offset TVD Offset North Offset East Horiz Bearing C-C Clear Dist Ellipse Sep ACR MASD ACR [feet] [feet] (feet] [feet] [feet] [feet] [feet] feet] [°] feet] [feet] feet] Status 0.00 0.00 0.00 0.00 0.00 0.00 69.25 -161.23 293.24 175.47 162.56 12.91 PASS 100.001 100.00 0.00 0.00 100.01 100.01 69.49 -161.12 293.33 175.47 162.55 12.92 PASS 137.381 137.38 0.00 0.00 137.30 137.30 69.70 -161.03 293.41 175.47 162.54 12.92 PASS 200.00 200.00 0.00 0.00 198.941 198.94 70.26 -160.89 293.59 175.57 162.62 12.95 PASS 300.001 299.87 -3.311 -2.84, 289.77 289.63 74.85 -161.91 296.17 177.52 162.86 14.671 PASS 400.001 398.991 -13.20] -1135! 381.62 380.84 85.28 -164.49 302.74 182.97 164.28 18.69 PASS 500.001 496.58 -29.61 -25.461 468.65 466.82 98.31 -167.54 312.00 193.48 173.98 19.50 PASS 600.001 591.93 -52.40 -45.051 545.04 __ 541.37 114.24 -172.15 322.67 215.59 195.35 20.24 PASS 700.001 _ 684.28 -81.41 70.001 _ 621.47 615.14 -. 132.90 _ -179.40 332.96 250.36 229.48 20.88 PASS ~~'-$OO.OOt 772.96 -116.41 --1~00.09~ 687; °~ 677.99 150.85 -I87.24 "~~ :; 341.44 296.72 275.45 21.27 PASS 900.001 857.27 -157.14 -135.11 741.77 729.05 168.04 -195.14 349.54 354.67 333.02 21.64 PASS 1000.001 936.58 -203.28 -174.79 790.49 773.84 185.19 -203.63 355.75 422.17 400.07 22.10 PASS 1100.001 1010.28 -254.49 -218.82 832.10 811.39 201.03 -212.03 0.85 497.09 474.54 22.56 PASS C-C Clearance Distance Cutoff: 5 00.00 feet • M MARATHON Clearance Report Closest Approach SD#5 Ver 2 Page 7 of 11 U!'~ BAKER t~lY6NES INTEQ Operator r ,. MARATHON Oil Company Slot SD#5 Area Cook Inlet, Alaska (Kenai Penninsula) Well SD#5 Field Ninilchik Field Wellbore SD#5 Ver 2 Facility Susan Dionne HOLE & CASING SECTIONS Offset Wellbore: SD #2 Offset Welloath: MWD <0-11094> String/Diameter Start MD [feet] End MD [feet] Interval [feet] Start TVD [feet] End TVD [feet] Start N/S [feet] Start E/W [feet] End N/S [feet] End E/W (feet] 12.25in Open Hole 0.00 1927.00 1927.00 0.00 1575.66 42.21 -98.29 282.49 -228.63 8.Sin Open Hole 1927.00 5962.00' 4035.00 1575.66 3433.02 282.49 -228.63. 1229.40 -766.46 Tin Open Hole 5962.00 11094.00 5132.00 3433.02 8006.91 1229.40 -766.46 1675.56 -1288.78' 9.625in Casing 0.00 1927.00 1927.00 0.00 1575.66 42.21 -98.29 282.49 -228.63 Tin Casing 0.00 5942.00 5942.00 0.00' 3419.91 42.21 -98.29 1225.56 -763.92 4.Sin Casing 0.00 11094.00 11094.00 0.00 8006.91 42.21 -98.29 1675.56 -1288.78 WELLPATH COMPOSITION offset Wellhnre: SD #2 offset Welloath: MWD <0-11I194> Start MD feet End MD [feet] Positional Uncertainty Model Log Name/Comment Wellbore 0.00 11094.00 NaviTrak (SAG) MWD <0-11094> SD #2 a. OFFSET WELLPATH MD REFERENCE -Offset Wellbore: SD #2 Offset Wellpath: MWD <0-11094> NID Reference: Datum #2 (RKB) Offset T[~D & local coordinates use Reference Wellpath settings (See WELLPATH DATUM on page 1 of this retiort) MARATHON Clearance Report Closest Approach SD#5 Ver 2 Page 8 of 11 ~LEARANCE DATA -Offset Wellbore: SD #3 Offset Wellpa Facility: Susan Dionne Slot: SD #3 Well: SD #3 Thre Ref MD Ref TVD Ref North Ref East Offset MD Offset TVD ffeetl ffeetl ffeetl ffeetl ffeetl ffeetl MWD <0- ~Id Value=0.00 feet ~ =interpolated/exl Offset North Offset East Horiz Bearing ffeetl ffeetl f°1 r~~~ BAKER I~IV6NES INTEQ polated station C-C Clear Dist Ellipse Sep ACR MASD ACR ffeetl ffeetl ffeetl Status 0.00 0.00 0.00 0.00 0.00 0.00 39.89 -203.31 281.10 207.19 194.27 12.91 PASS 100.001 100.00 0.00 0.00 98.92 98.92 40.11 -203.53 281.15 207.45 _ 194.53 12.92 PASS 200.00 200.00 0.00 0.00 198.06 198.06 40.75 -204.15 281.29 208.19 195.24 12.94 PASS 300.001 299.87 -3.31 -2.84 293.01 292.98 42.28 -205.77 282.66 208.10 194.08 14.02 PASS 400.OOt 398.99 -13.20 -11.35 383.03 382.83 45.66 -209.83 286.52; 207.65 190.78 16.87] PASS 500.001 496.58 -29.61 -25.46 467.31 , 466.54 51.84 -217.34 293.00 210.61 192.88 17.73. PASS 600.001 591.93 -52.40 -45.05 546.90 544.80 60.50 -228.82 301.57 220.76 201.96 18.80 PASS 700.001 684.28 -81.41 -70.00 __ 623.05 618.62 70.87 -244.32 311.14 240.60 220.74 19.86 PASS 800.001 772.96 -116.41 __ -100.09 _ 695.12 687.19 82.17 -263.36 320.58 271.01 250.13 20.88 PASS 900.001 857.27 -157.14' -135.11 __ 766.72 753.82 94.05 -286.69 328.89 311.08 288.98 22.11' PASS 1000.001 936.58 -203.28 -174.79 836.49 817.25 105.34 -313.44 335.81 358.76 335.44 23.33 PASS 1100.001 1010.28 -254.49 -218.82 900.55 873.90 115.84 -341.43 341.68 413.26 388.43 24.84 PASS 1200.001 1077.82 -310.38 -266.87 962.66 927.55 126.77 -370.74 346.63 473.79 447.08 26.71 PASS C-C Clearance Distance Cutoff: 5 00.00 feet WELLPATH COMPOSITION Offset Wellbore: SD #3 Offset Wellnath: MWD <0-10255> • Start MD [feet] End MD [feet] Positional Uncertainty Model Log Name/Comment Wellbore 0.00 10255.00 NaviTrak (Standard) MWD <0-10255> SD #3 M MAFIITNON Clearance Report Closest Approach SD#5 Ver 2 Page 9 of 11 r~~r BAKER NYt~NES INTEQ I~ Reference: Glacier #1 (RKB) Offset TVD & local coordinates use Reference Wellpath settings (See WELLPATH DATUM on page 1 of this report) • ~,rn., ~ _~~_~~. ~ _~~. - .,. .u ,.: _ .~ ~t . n. ~ ~ OFFSET WELLPATH MD REFERENCE -Offset Wellbore: SD #3 Offset Wellpath: MWD <0-10255> M MARATHON Clearance Report Closest Approach SD#5 Ver 2 Page 10 of l 1 r~.~ BAKER Nu6NEs INTEQ Operator ,. ~ ~ MARATHON Oil Company Slot SD#5 Area Cook Inlet, Alaska (Kenai Penninsula) Well SD#5 Field Ninilchik Field Wellbore SD#5 Ver 2 Facility Susan Dionne C-C Clearance Distance Cutoff: 500.00 feet M MARATHON Clearance Report Closest Approach SD#5 Ver 2 Page 11 of 11 ~~~ BAKER NYt~NES INTEQ Operator ,. ~ ~ MARATHON Oil Company Slot SD#5 Area Cook Inlet, Alaska (Kenai Penninsula) Well SD#5 Field Ninilchik Field Wellbore SD#5 Ver 2 Facility Susan Dionne HOLE & CASING SECTIONS Offset Wellbore: SD #4 Offset Wellpath: MWD <a11953> String/Diameter Start MD [feet] End MD [feet] Interval [feet] Start TVD [feet] End TVD [feet] Start N/S [feet] Start E/W [feet] End N/S [feet] End E/W [feet] 12.25in Open Hole 0.00 1861.00 1861.00 0.00 1545.68 -28.03 -44.67: -45.75 -298.54 8.Sin Open Hole 1861.00 6116.00 4255.00 1545.68 3404.73. -45.75 -298.54 -142.26 -1460.94 6.125in Open Hole 6116.00 11953.00 5837.00 3404.73 8366.58 -142.26 -1460.94 -195.77 -2074.84 20in Conductor 0.00 122.00 122.00 0.00 122.00 -28.03 -44.67 -28.03 -44.67 9.625in Casing 0.00 1851.00 1851.00 0.00 1540.92 -28.03 -44.67 -45.51' -295.87 Tin Casing 0.00 6097.00 6097.00 0.00 3396.33 -28.03 -44.67 -141.85 -1455.76 4.Sin Liner 0.00 11953.00' 11953.00 0.00 8366.58 -28.03 -44.67 -195.77 -2074.84 ~.. WELLPATH COMPOSITION Offset Wellbore: SD #4 Offset Well ath: MWD <0-11953> Start MD End MD Positional Uncertainty Model Log Name/Comment Wellbore feet] feet] 0.00 11953.00 NaviTrak (SAG) MWD <0-11953> SD #4 ,, ,,.. ~. ~M~ ,: n, s .,~ :OFFSET WELLPATH MD REFERENCE -Offset Wellbore: SD #4 Offset Wellpath: MWD <0-11953> 1V1D Reference: Glacier 1 (RKB) Offset TVD & dotal coordinates use Reference Wellpath settings (See WELLPATH DATUM on naQe 1 of this report) ~ Local coordinates _ Grid coordinates Geographic coordinates North [feet] East [feet] Easting [US feet] Northing [US feet] Latitude [°] Longitude [°] Slot Location 242.07 -1265.93 213176.67 2236631.97 60 06 46.740N 151 34 20.265W Facility Reference Pt 214436.50 2236359.99 60 06 44.356N 151 33 55.287W Field Reference Pt 226657.85 2252005.12 60 09 21.189N 151 30 01.220W R 1 Calculation method Minimum curvature ~ ti_._ ....~ .. , Glacier 1 (RKB) to Facility Vertical Datum 156.00 feet 'Horizontal Reference Pt Slot Glacier 1 (RKB) to Mean Sea Level 156.00 feet Vertical Reference Pt Glacier 1 (RKB) Facility Vertical Datum to Mud Line 0.00 feet MD Reference Pt Glacier 1 (RKB) 'Field Vertical Reference Mean Sea Level rr~~r Wellpath Design Summary Report BAKER Wellpath: SD#5 Ver 2 MYl~irNES MARATHON Page 1 of 2 INTEQ MARATHON Wellpath Design Summary Report Wellpath: SD#5 Ver 2 Page 2 of 2 INTEQ Operator ~. ~ ~ MARATHON Oil Company Slot SD#5 Area Cook Inlet, Alaska (Kenai Penninsula) Well SD#5 Field Ninilchik Field Wellbore SD#5 Ver 2 Facility Susan Dionne ELLPATH DATA (7 stations) MD [feet] Incliuatiou [°] Azimuth [°] TVD [feet] Vert Sect [feet] North [feet] East [feet] Grid East [us survey feet] Grid North [us survey feet] DLS [°/100ft] esigu Commeut 0.00 0.000 220.689 0.00 0.00 0.00 0.00 213176.67 2236631.97 0.00 Tie On 200.00 0.000 220.689 200.00 0.00 0.00 0.00 213176.67 2236631.97 0.00 nd of Tangent 1425.29 61.264 220.689 1204.79 594.99 -451.16 -387.91 212778.14 2236190.17 5.00 uild (S) 3054.40 61.264 220.689 1988.02 _ 2023.47 __ ~ -1534.31 _ _ -1319.22 211821.33 2235129.49 0.00 nd of Tangent (S) 6117.61 0.000 - 220.689 4500.00 ~ 3510.96 ~ _ - - --------- -2662.20 -2289.00 210825.00 ------- 2234025.00 --- 2.00 rop (S) 7338.61 0.000 220.689 5721.OOt 3510.96 -2662.20 -2289.00 210825.00 2234025.00 0.00 nd of Tangent 9617.61 0.000 220.689~000.OOZI 3510.96 -2662.2 02289.00' 210825.00 2234025.00 0 00 nd of Tangent TARGETS Name MD [feet] TVD [feet] North [feet] East [feet] Grid East [us survey feet] Grid North [us survey feet] Latitude [o] Longitude [o] Shape 3483.00 -2662.20 -2289.00 210825.00 2234025.00 60 06 20.519N 151 35 05.419W circle SD#5 Tyonek Tgt - 4/27/06 4123.00 -2662.20 -2289.00 210825.00 2234025.00 60 06 20.519N 151 35 05.419W circle SD#5 T2 Tgt - 4/27/06 7338.61 ~ 5 21.00 -2662.20 -2289.00 210825.00 2234025.00 60 06 20.519N 151 35 05.419W circle 1) SD#5 T3 Tgt - 3/22/06 9617.61 8000.00 -2662.20 -228 "' ~ °~~ circle 2) SD#5 TD Tgt - 4/27/06 SURVEY PROGRAM Ref Wellbore: SD#5 Ver 2 Ref Well ath: SD#5 Ver 2 Start MD [feet] End MD [feet] Tool Type Positional Uncertainty Model Log Name/Comment Wellbore 0.00 7343.61 NaviTrak aviTrak (Standard) SD#5 Ver 2 J • ~i~ • Marathon Oil Company Well Name: Susan Dionne #5 Location: Kenai, Alaska. INTEGRATED FLUIDS ENGINEERING PROJECT PLAN IFE Prepared For: MARATHON OIL COMPANY Well Susan Dionne #5 Prepared by: Tony Tykalsky Reviewed by: Hal Martins Presented to: Will Tank June 9, 2006 Kenai Peninsula, Alaska • r-e Marathon Oil Company PO Box 190168 Anchorage, Alaska 99519 ATTN: Will Tank Will: Marathon Oil Company Well Name: Susan Dionne #5 Location: Kenai, Alaska. Enclosed is the recommended drilling fluid program for the Susan Dionne #5 Well to be drilled this year. The following is a brief synopsis of the program. Overview: SD #5 is a development well targeting the Tyonek formation at the Susan Dionne field. A GeUGelex spud mud is recommended for the surface interval. Two Flo-Pro fluids will be used for the intermediate and production intervals. After logging the production interval, the well will be completed with 4-1/2" liner cemented in place. Surface Interval: A standard fresh water GeUGelex spud mud will 6e used. Initial funnel viscosity should be in the 50 - 75 sec/qt range. Lower funnel viscosity to 45 - 60 sec/qt after gravel has been drilled. Lower fluid loss to 10 - 12 cc's API prior to running surface casing. Intermediate Interval: This interval will be drilled with the same type of Flo-Pro fluid used on the NS #2 well. After drilling out the surface cement, the well will be displaced to the new fluid. SafeCarb bridging material will be maintained according to the mud program to minimize losses to the formation. Lubricants should be added on a as-needed basis. Production Interval: This interval will be drilled with the standard non-damaging Flo-Pro fluid used on non-excape wells. After drilling out the intermediate cement and 20 - 25 feet of new hole, the well will be displaced to the new fluid. Fluid loss should be maintained @ 5 - 7 cc's API for this interval. Completion: The completion will consist of a 4-1/2" liner cemented in place. This will be tied back to the surface with a 4- 1/2" completion string. Corrosion control will be added to the 6% KCl brine that will remain in the 4-1/2" x 7" annulus prior to tie-back. Tony Tykalsky Project Engineer M-I Drilling Fluids Reference Well: SD #3, SD #2, SD #4 NOTE: This program is provided as a guide only. Well conditions will always dictate fluid properties reauired. ~~ • • Marathon Oil Company Well Name: Susan Dionne #5 Location: Kenai, Alaska. EXECUTIVE SUMMARY Our overall goal is no M-USwaco HSE incidents while providing fluids and solids control services to our customer. Our goal for SD #5 is to remove drill solids from the mud system at a cost of less ~ than $0.29 per pound. This has been the average for the last four years of centrifuge ~ van operations Our goal for SD 35 is to drill the well at a fluid cost of less than $22.26 per foot. This total is products only and does not include engineer service. Target for fluid volume usage for this well is set at < 4338 barrels. The Mongoose shakers recently installed have allowed us to run finer shaker screens than =~' ^~ previously, thereby reducing dilution requirements. • 1~ • Marathon Oil Company Well Name: Susan Dionne #5 Location: Kenai, Alaska. Interval Benchmarks and Targets DriNing Intervals Depth Benchmark 1 Benchmark 2 Benchmark 3 Benchmark 4 Interval ~~) Fluid cost per foot Volume Usage Solids Removal 0 - 1623' < $6.33 ft < 1346 bbls 1623 - 4768' < $29.18 ft < 1291 bbls 4768 - 9618' < $22.26ft < 1501 bbls Total Project Avg. Max. Targets for < $22.26 < 4338 bbls < $0.291b o Spills from Centrifug Drilling Van Operation Interval ~~ • • ~_,'~ Marathon Oil Company Well Name: Susan Dionne #5 Location: Kenai, Alaska. Project Summary Casing Hole Casing Depth TVD Mud Mud Sum Interval Size Size Program System Weight Days Product 8 Service (in) (in) (ft) (ft) Solids Control (ppg) Cost 9-5/8" 12-1/4" 1623' 1300' Gel/Gelex Spud 8.6 - 9.4 7 $16,077 Mud Screens 150/180 mesh Desilter Centrifuge Van 7" 8-1/2" 4768' 3200' Flo-Pro 9.4 - 9.8 7 $91,771 w/SafeCarb Screens 180 - 210 mesh Desilter Centrifuge Van 4-1/2" 7" 9618' 8000' Flo-Pro 9.4 - 9.8 9 $112,050 w/SafeCarb Screens 230 - 210 mesh Desilter Centrifuge Van 4-1/2" 7" Completion 9618' 8000' 6% KCl 8.55 4 $9,416 - Utilize all solids control equipment to minimize the build up of drill solids in the system (if possible, centrifuge the surface mud during trips to reduce drill solids). - Condition the mud prior to running casing for all intervals. - Cost does not include any considerations for whole mud losses. - Cost includes 3% Lubetex concentration for intermediate and production interval. IFE • • 1_~ 1~ Marathon Oil Company - Well Name: Susan Dionne #5 Location: Kenai, Alaska. Product Usage Summary (estimate) PRODUCT Surface 12-1/4" Intermediate 8-1/2" Production 7" Completion 4-1/2" Total Usage % of Total Cost M-I Bar 0 194 1200 0 1394 4.85 M-I Gel 404 0 0 0 404 1.63 Gelex 17 0 0 0 17 0.13 Soda Ash 7 6 15 0 28 0.23 Caustic Soda 7 13 15 0 35 0.68 Con or 404 0 3 5 0 8 4.66 Sodium Meta Bisulfate 13 13 15 1 42 1.27 Bicarb 7 6 15 0 28 0.23 Con or 303A 0 0 0 1 1 0.22 F1oVis 0 90 105 0 195 18.62 Desco CF 18 0 0 0 18 0.39 DualFlo 0 0 75 0 75 2.84 Polypac UL 27 45 0 0 72 5.21 KCl 0 542 630 84 1256 10.71 Kla and 0 18 20 0 38 12.19 SafeCarb 10 0 258 300 0 558 4.91 Lubetex 0 31 36 0 67 22.70 Defoam X 0 7 8 0 15 0.65 En ineer Service 7 7 9 4 27 IFE • • '~ Marathon Oil Company Well Name: Susan Dionne #5 _ Location: Kenai, Alaska. Offset Well Information Well Hole Size Depth PPG PV YP FL Comments SD #3 12.25" 254 8.6 15 38 N/C Spud in, drlg ahead 1370 9.1 16 30 14 Drlg ahead 1875 9.1 15 29 13.8 Trip for motor, drlg ahead 1972 9.2 11 14 14.8 Drlg to TD, r/u & run 9-5/8" csg 8.5" 3100 9.3 9 30 8 New mud, drlg out & drlg ahead 4190 9.55 11 24 7.4 Drlg ahead, lots of clays 4756 9.5 10 34 7.2 Short trip, bridge, dump mud to reduce drill solids 5245 9.5 15 28 6.6 Add 3% lubetex to help sliding 5245 9.8 12 28 6.8 Wiper trip, hit bridges, increase PPG with barite, ru 7" csg 6.125" 5635 9.5 9 19 7.7 Drlg out, disp to new mud, drlg to coring point 5693 9.4 9 21 7.6 Core 5721 9.4 10 22 7.2 Core 6310 9.4 11 28 7.9 Log & drlg ahead 6879 9.5 12 27 6.5 Drlg ahead no problems 7745 9.55 13 29 5.9 Drlg ahead, log to 6879' 8445 9.6 14 30 6.2 Drlg ahead, POH for washout 8772 9.7 15 29 7.4 Inc mud weight for core 8887 9.75 13 21 6.8 Run centrifuge van to lower solids 9357 9.8 14 27 6.4 Finish core, drlg ahead, centrifuge solids 9439 9.85 14 27 6.4 Trip for bit 9785 9.8 13 23 5.9 Drlg ahead, trip for washout, RIH 10100 9.75 12 22 5.7 Drlg ahead 10254 9.7 12 22 6.2 Drlg to TD, log hole, fish for logging tool 10254 9.7 10 14 7.2 Run liner, briefly stuck, reduce PPG, run liner & cement same • • '~ Marathon Oil Company Well Name: Susan Dionne #5 _ Location: Kenai, Alaska. Offset Well Information Well Hole Size Depth PPG PV YP FL Comments SD #2 12.25" 618 8.85 16 26 15.2 Spud in, trip for MWD 1723 9.4 16 23 7.8 Drlg ahead, no hole problems 1927 9.45 13 14 8.2 Drlg to TD, run surface casing, cement same 8.5" 3154 9.25 12 26 8 Drlg out, disp to new mud, drlg ahead 4924 9.4 11 22 8.2 Drlg ahead, short trip OK, drlg ahead 5692 9.55 15 23 7.2 Drlg to csg point, trip out tight in spots. (5100 - 4558') 5692 9.75 12 23 7.6 Long hole on D.P., R/U & run 7" casing 7" 5987 9 10 18 6.2 Drlg out, displace to new mud, LOT 18.8 PPG, drlg ahead 6362 9 12 23 4.8 Drlg ahead add 5% lubricant for sliding/torque 6696 9.2 12 23 4 Drlg ahead, short trip OK, drlg ahead 7216 9.15 13 24 3.8 Drlg ahead, centrifuge mud for weight control 7968 9.25 13 24 3.6 Drlg ahead, short trip OK, drlg shed 8517 9.2 14 27 3.8 Drlg ahead, run centrifuge for PPG 9253 9.35 12 30 4.4 Drlg shed, Ok 9573 9.4 13 33 4.4 Trip for BHA, OK, drlg ahead 9967 9.5 12 33 4.4 Drlg ahead 10657 9.5 12 32 4 Drlg ahead, POH for washout 11094 9.7 13 32 4.2 Replace joint, drlg to TD, wiper trip to shoe, OK, 11094 9.85 14 31 4.4 Circ hole clean, Log hole on DP. 11094 9.7 13 30 4.8 Condition hole, centrifuge fluid down to 9.7 PPG 11094 9.7 13 30 5 Run 4-1/2" tubing, stuck @ 8000', pump Lubetex pill, free string, run to TD, cement casing, (possible dill. sticking) SD #4 12.25" 561 8.8 14 23 14 Spud in, stuck @ 200' (bouilder), free pipe, drlg ahead 1861 9.3 15 22 8.2 Drill to interval T.D. 1861 9.55 16 16 8.4 Run ~ cement 9-5/8" casing 8.5" 3117 9.2 11 21 7 Drlg out, disp to new mud, drlg ahead, tight on short trip @ 2673' 4590 9.35 13 26 7.4 Drlg ahead, short trip, pump out from 4167 - 3534' NOTE: Pumped lo-vis/hi-vis sweeps with good results 6116 9.7 16 33 7.8 Drlg ahead, short trip, pump out from 4590 - 4179' 6116 9.7 19 28 6.8 Log well, wiper trip (hole un-loaded cuttingw) add 3% Lubetex for casing run 6116 9.7 19 26 7.2 Run and cement 7" casubg 6.125" 7330 9.5 7 17 4.6 Drlg out, displace to new mud, drlg ahead (3% lubetex) 8255 9.8 9 22 4.8 Drlg ahead to 1st coring point. POH 8345 9.8 9 19 5.4 Core #1 OK 8707 9.75 8 19 5.8 Drlg ahead, POH for washout, drlg ahead 9310 9.85 11 28 5 Drlg ahead, increase lubetex to 4% 9822 9.8 11 28 5.2 Drlg ahead 10924 9.8 10 24 6.2 Drlg ahead to 2nd coring point, POH (tight) 10969 9.8 11 23 6 Core #2 (two runs) 11031 9.8 11 24 5.6 UD Core, RIH drlg ahead 11505 9.8 11 20 5.4 Drlg ahead 11685 9.9 11 19 5.8 Drlg to T.D. of well 11953 10.1 13 21 5 Weigt up to control gas, log well (4-1/2% lubetex) 11953 10.1 11 22 4.1 R/U and run 4-1/2" liner. 11953 10.1 12 22 4.2 Cmt liner, dsp well to brine, UD drlg pipe, run 4-1/2" tubing 1~ • • Marathon Oil Company Well Name: Susan Dionne #5 Location: Kenai, Alaska. Plans & Procedures ~ COMMUNICATION -The Field Mud Engineer will communicate daily with the In-Town Project Engineer. The Project Engineer will then communicate daily with the rig Drilling Engineer. Communications should be about, but not limited to, fluid properties, hole difficulties, possible changes to the mud program, and proposals to use products not included in the mud program. ~ FLUID LOSS CONTROL - In the intermediate interval the API fluid loss will be maintained in the 7 - 9 cc's range. In the production interval the API fluid will be maintained in the 5 - 7 cc's at all times. In addition to sufficient fluid loss agent additions, this may require adequate dilution of the mud system in order to keep reactive drill solids to a minimum . It is particularly important to maintain a low hardness (<200 ppm Ca) for effective use of DualFlo, therefore cement contamination should be completely treated as rapidly as possible prior to adding DualFlo to control or reduce fluid loss. NOTE: If additions of DualFlo do not appear to be lowering the fluid loss adequately, then switch to additions of Polypac Supreme SL after consultation with town. ~ LSRV - Note Change. In the 8-1/2" interval, maintain the LSRV above 40,000. In the 6-1/8' interval, maintain the LSRV above 30,000. These guidelines will promote more effective hole cleaning and reduce fluid loss to the formation. ~ DRILL SOLIDS -MBT -The MBT should be kept at less than 5 ppb in the production interval through aggressive use of solids equipment and dilution as needed. ~ MIXING CONDITIONS -Whenever possible all treatments to the mud system should be made as pre-mix additions. Polymers and KCl should first be mixed in fresh water in that order and then blended into the active system over one or two circulations as needed. ~ CORROSION - Congor 404 additions should be made daily when drilling with F1oPro fluid in order to maintain a Congor 404 concentration of +/- 2000 PPM. ~ CORRISION - Sodium Meta Bisulfate additions should be made daily as needed with any fluid in the hole. Maintain a DO reading of less than 3 PPM. ~ SOLIDS VAN USAGE -The Solids Van should be used whenever drill solids become un-acceptably high and reduction of drill solids in the mud can be more economically done with centrifuging and dilution then just with dumping and diluting. The weight of the drilling fluid alone should not be the determining condition for when to use the Solids Van. ~ WEIGHTING UP -All increases in mud weight should be accomplished with barite additions. In the production interval, insure chloride concentration is maintained at 30,000 to minimize the need for barite additions. ~ BEWARE OF STICKING PROBLEMS THAT OCCURRED ON SUSAN DIONNE WELLS (see offset well history) ~~ • • Marathon Oil Company Well Name: Susan Dionne #5 Location: Kenai, Alaska. Interval Summary -12-1/4" hole 0 -1623' Drilling Fluid System GeUGelex Spud Mud Key Products MI Gel / Gelex /Soda Ash /Caustic Soda / MI Bar / PolyPac Supreme UL /Sodium Meta Bisulfate Solids Control Shale Shakers / Desilter /Centrifuge Van Recommended shaker screens - 150 - 180 mesh Potential Problems Lost circulation, coal sloughing, drill solids build-up, angle building ifficulties Interval Drilling Fluid Properties Depth Mud Funnel Yield API Drill Interval Weight Viscosity Point Fluid Loss pH Solids (ft) (ppg) (sec./qt) (Ib./100ft2) (mV30min) (%) 0 - 1623' 8.6 - 9.4 60 - 100 25 - 35 NC - 10/12 +/- 9.5 < 7% - Treat drill water with Soda Ash to reduce hardness. - Build spud mud with 20 - 25 PPB M-I Gel to +/- 100 sec.gt funnel viscosity. - Lower funnel viscosity to +/- 60 after any gravel zone has been drilled. - Add Gelex as needed to maintain sufficient viscosity for hole cleaning. - Maintain DO reading of less than 3 ppm with additions of Sodium Meta Bisulfate. - Increase funnel viscosity if fill on connections begins to occur. - Reduce fluid loss with additions of Polypac Supreme UL prior to running surface casing. - Add 2 - 5 PPB of M-I Seal Fine to mud system if seepage losses becomes a problem.. - Condition mud prior to cementing casing to reduce yield point and gel strengths. - Estimated volume usage for interval - 1346 barrels. - Estimated haul off volume - 1892 barrels. ~~ ~~ • ~~ v Marathon Oil Company Well Name: Susan Dionne #5 Location: Kenai, Alaska. Interval Summary - 8-1/2" hole 1623 - 4768' Drilling Fluid System Flo-Pro Fluid Key Products Flo-Vis / PolyPac UL / KCl / SafeCarb 10 /Asphasol Supreme / Lubetex / Caustic Soda / Congor 404 /Sodium Meta Bisulfate / Kla and Solids Control Shale Shakers / Desilter /Centrifuge Van Recommended shaker screens - 210 mesh Potential Problems Lost circulation, coal sloughing, drill solids build-up, gas kick, tight hole conditions nterval Drilling Fluid Properties Depth Mud Plastic LSRV API Drill Interval Weight Viscosity 1 min Fluid Loss pH Solids (ft) pg) (c .) (c s) (m1I30min) (%) 1623 - 4768' 9.4 - 9.8 8 - 12 > 40,000 7 - 9 +/- 9.5 +/- 7.5 - Use one rig pit to drill out surface casing. In other rig pits, build new Flo-Pro fluid using the enclosed formula. - After drilling out surface casing, displace hole to Flo-Pro fluid prior to running leak off test. - Maintain DO reading of less than 3 ppm with additions of Sodium Meta Bisulfate. - Maintain Conqor 404 concentration of 2000+ ppm. If running coals become a problem, increase Asphasol Supreme additions. - Estimated volume usage for interval - 1291barrels. - Estimated haul off volume - 1765 barrels. - Condition mud prior to running 7" casing. NOTE: Follow BOSCO guidelines when adding biocide, oxygen scavenger and corrosion inhibitor. ~~ ~~ • • ~.'~ Marathon Oil Company Well Name: Susan Dionne #5 _ Location: Kenai, Alaska. Intermediate Interval Fluid Formula ~~ S~/~+~ MUDCALC 4.5 -Water-Based Mud Calculation 8-1/2" Interval from 1623 - 4768' In ut Out ut -1 bbl Order of Products Concentration Volume Product Addition Field, Ib Lab, m Field, bbl Lab, mi Usa e 1 Water 317.07 317.07 0.906 317.07 2 Soda Ash 0.25 0.25 0.000 0.10 Reduce Hardness 3 Flovis 2.00 2.00 0.004 1.33 Viscosi 4 Pol ac Su reme UL 2.00 2.00 0.004 1.25 Fluid Loss Control 5 Caustic Soda 0.50 0.50 0.001 0.23 H Control 6 KlaGard 6.00 6.00 0.016 5.45 Inhibition 7 As hasol Su reme 4.00 4.00 0.010 3.33 Wellbore Stabili 8 Potassium Chloride 20.24 20.24 0.024 8.47 Inhibition 9 Con or 404 2.00 2.00 0.004 1.43 Corrosion Control 10 SafeCarb 10 10.00 10.00 0.010 3.57 Brid in A ent 11 MI Bar 30.24 30.24 0.021 7.20 Mud Wei ht 12 Sodium Meta Bisulfate 0.50 0.50 0.002 0.56 Ox en Scaven er If for ue becomes a roblem add u to 5% of the followin 13 Lubetex 14.00 14.00 0.041 14.43 Lubrici Total 394.8 394.8 Estimated Volume Usa a 1291 barrels Catcutated Mud Wei ht Total Chloride 9.400 29600 Descri tion ' SD #5 Intermedi ate Interval Mud Wei ht 9.4 Preh rated Gel No Wei ht Material Code MI Bar Preh rated Gef Conc. Wei ht Material SG 4.2 KCI Chloride Wei ht Material Price KCI Wt% 6 • ~~ • Marathon Oil Company Well Name: Susan Dionne #S Location: Kenai, Alaska. Interval Summary - 7" hole 4768 - 9618' Drilling Fluid System __ Flo-Pro Fluid Key Products Flo-Vis / DualFlo / KCl / Greencide 2SG / SafeCarb 10/ MI Bar / Caustic Soda / Conqor 404 /Sodium Meta Bisulfate / Kla and / Lubetex / As hasol Su reme Solids Control Shale Shakers / Desilter /Centrifuge Van Recommended shaker screens - 210 - 230 mesh Potential Problems Lost circulation, coal sloughing, drill solids build-up, gas kick, tight hole conditions, stuck pipe. nterval Drilling Fluid. Properties Depth Mud Plastic LSRV API Drill Interval Weight Viscosity 1 min Fluid Losa pH Solids (ft) (ppg) (cp.) (cps) (mU30min) (%) 4768 - 9618' 9.4 - 9.8 10 - 14 > 30,000 S - 7 +/- 9.S +/- S% - Use one rig pit for drilling out intermediate casing. In other rig pits, build new Flo-Pro fluid using the enclosed formula. - NOTE: Initial formula does not call for Lubricant. However lubricant additions should be monitored for there effectiveness with the enclosed data sheet. - Estimated volume usage for interval - 1 SO1 barrels. - Estimated haul off volume - 2778 barrels. - Condition mud prior to running 4-1/2" casing. NOTE: Follow BOSCO guidelines when adding biocide, oxygen scavenger and corrosion inhibitor. ~~ • • Marathon Oil Company Well Name: Susan Dionne #5 Location: Kenai, Alaska. Production Interval Fluid Formula M~ ~~~ M-I L.L.C. MUDCALC 4.5 -Water-Based Mud Calculation 7" Interval from 4768 - 9618' In ut Out ut -1 bbl Order of Products Concentration Volume Product Addition Field Ib Lab m Field, bbl Lab ml Usa e 1 Water 317.07 317.07 0.906 317.07 2 Soda Ash 0.25 0.25 0.000 0.10 Reduce Hardness 3 Flovis 1.50 1.50 0.040 1.00 Viscosi 4 DualFlo 5.00 5.00 0.010 3.33 Fluid Loss Control 5 Caustic Soda 0.50 0.50 0.001 0.23 H Control 6 KlaGard 6.00 6.00 0.016 5.45 Inhibition 7 As hasol Su reme 2.00 2.00 0.005 1.67 Wellbore Stabili 8 Potassium Chloride 20.24 20.24 0.024 8.47 Inhibition 9 Con or 404 2.00 2.00 0.004 1.43 Corrosion Control 10 SafeCarb 10 10.00 10.00 0.010 3.57 Brid in A ent 11 MI Bar 51.42 51.42 0.035 12.24 Mud Wei ht 12 Sodium Meta Bisulfate 0.50 0.50 0.002 0.56 Ox en Scaven er If for ue becomes a roblem add u to 5% of the followin 13 Lubetex 14.00 14.00 0.041 14.43 Lubrici Total 411.6 411.6 Estimated Volume Usa a 1501 barrels Calculated Mud Wei hf Total Chloride 9.800 29600 Descri tion SD #5 Production Interval .Mud Wei ht 9.4 reh drated Gel No Wei ht Material Code MI Bar rated Gel Conc. Wei ht Material SG 4.2 KCI Chloride Wei ht Material Price KGI Wt% 6 ~~ ~~ h //i • Marathon Oil Company Well Name: Susan Dionne #5 Location: Kenai, Alaska. Interval Summary -Completion Procedures Corrosion Control Additive in Casing x Tubing Annulus Well Susan Dionne #5 Volumes: Tubing Volume 4-112" Tubing 7o.7a barrels Annular Volume Casing x Tubing 88.68 barrels 3.992 x 4568 ft Packer @ 4568 ft MD 6.276 @ 4768 ft MD 4.50 @ 9618 ft MD Total Annular Volume 88.68 Tubing Volume 7o.7a Total Hole Volume 159.42 Treatment Procedures. 1. After the 4-1/2" tubing is run and the drilling fluid is conditioned, build at least 160 barrels of 6% KCL brine. 2. Displace mud out of well with the 6% KCL brine. Add 1 drum of Conqor 303A and 1 sack of Sodium Meta Bisulfate to the first 90 barrels of brine pumped., 3. Displace the 90 barrels of treated fluid with an additional 70 barrels of brine prior to setting the tubing hanger. 4. This procedure will place corrosion control in the 4-1 /2" x 7" annulus. IFE~"', • • '~ Marathon Oil Company Well Name: Susan Dionne #5 Location: Kenai, Alaska. HSE Issues HANDLING OF DRILLING FLUID PRODUCTS HEALTH AND SAFETY 1. Drilling crews should be instructed in the proper procedures for handling fluid products. 2. Personal Protective Equipment (PPE) charts should be posted in the pit room, the mud lab, and the office of the Drilling Forman. 3. PPE must be in good working order and be utilized as recommended by the PPE charts. 4. Product additions should be made with the intent to use complete unit amounts of products (sacks, drums, cans) as much as possible in order to minimize inventory of partial units. 5. Insure all MSDS sheets are up to date and readily available for workers to access for information. ENVIRONMENTAL 1. Insure that all product stored outside is protected from the weather. 2. Do not store partial units (sacks, etc) outside if possible. 3. Properly secure all products for shipment between job sites. 4. When transferring fluid and or cuttings from the rig to trucks, insure all hoses are properly secured. 5. When utilizing the centrifuge solids van, insure all hoses and connections between the van and the rig are secure. ~~ ~~ • • Marathon Oil Company Well Name: Susan Dionne #5 Location: Kenai, Alaska. Product Health and Safety Reference HMIS HAZARD RATINGS Product Function Health Flammabilit Reactivit PPE ASPHASOL SUPREME Shale Inhibitor 1 1 0 J BORAX Inorganic Borate 1 0 0 E CALCIUM CHLORIDE Densifier 1 0 0 E CIRTIC ACID pH Adjuster 1 0 0 E CONCOR 303A Corrosion Inhibitor 2 1 0 E CONCOR 404 Corrosion Inhibitor 1 1 0 J D-D CWT Fluids Additive 2 1 0 .1 DEFOAM X Defoamer 1 1 0 J DESCO CF Dispersant 1 1 0 E DUAL-FLO Fluids loss reducer 1 1 0 E FORM-A-SET AK Loss circulation Material 1 1 0 E FORM-A-SET XL Fluids Additive 2 1 0 E FORM-A-SET RET Loss circulation Material 1 1 0 J HEC-10 Viscosifier 1 1 0 E FLO-VIS PLUS Viscosifier 1 1 0 E STEEL LURE EP Oil well additive Lubricant 1 2 0 J SODIUM BICARB Alkalinity control 1 0 0 E SODIUM META Oxygen Scavenger 1 1 0 J GELEX Bentonite Extender 1 0 0 E G-SEAL Graphite LCM 1 1 0 E KLAGARD Shale Control 0 1 0 J LUBETEX Lubricant 1 1 0 .l MI BAR Weighting Agent *1 1 0 E MI GEL Viscosifiet *1 1 0 E MI SEAL F, M, C LCM *1 1 0 E IFE __~- ,1~ • Marathon Oil Company Well Name: Susan Dionne #5 Location: Kenai, Alaska. Product Health and Safety Reference HMIS HAZARD RATINGS MIX II F, M, C LCM *1 1 0 E NUT PLUG F, M, C LCM *1 1 0 E POLYPAC'S Fluid Loss Control *1 1 0 E Potassium Chloride Shale Inhibitor, Densifier 1 0 0 E SafeCarbs (all) Bridging "weighting agent *1 0 0 E SAFEKLEEN Surfactant 1 1 0 J SALT Densifier 1 0 0 E SAPP Dispersant *1 0 0 E SODA ASH Calcium precipitation 1 1 0 E DRILLZONE ROP Enhancer 1 1 0 J SCREENKLEEN Dispersant/Emulsifyer 1 1 0 J BIOBAN BP-PLUS Biocide 2 1 1 J GREENCIDE 25G Biocide 3 0 0 J CAUSTIC POTASH Alkalinity Control 3 0 1 X HAZARDOUS MATERIALS IDENTIFICATION SYSTEM (HMIS) HAZARD RATINGS 4 -Severe hazard 3 -Serious hazard 2 -Moderate hazard 1 -Slight hazard 0 -Minimal hazard * An asterisk next to the health rating indicates that a chronic hazard is associated with the material. HMIS PERSONAL PROTECTIVE EQUIPMENT INDEX A -Safety Glasses B -Safety Glasses, Gloves C -Safety Glasses, Gloves, Synthetic Apron D -Face Shield, Gloves, Synthetic Apron E -Safety Glasses, Gloves, Dust Respirator F -Safety Glasses, Gloves, Synthetic Apron, Dust Respirator G -Safety Glasses, Gloves, Vapor Respirator H -Splash Goggles, Gloves, Synthetic Apron, Vapor Respirator I -Safety Glasses, Gloves, Dust and Vapor Respirator J -Splash Goggles, Gloves, Synthetic Apron, Dust and Vapor Respirator K -Air Line Hood or Mask, Gloves, Full Suit, Boots X -Consult your supervisor for special handling directions IFE • • '~ Marathon Oil Company Well Name: Susan Dionne #5 Location: Kenai, Alaska. Contacts Contact Title a-mail Work Cellular MSDS Emergency 281561-1600 Contact Pete Berga Drilling pkberga@marathonoil.com 907 565-3032 907 231-0663 Marathon Superintendent Will Tank Drilling Engineer wjtank@marathonoil.com 713 296-3273 713 203-8398 Marathon Tony Tykalsky Project Engineer ttykalsky@miswaco.com 907 274-5011 907 227-2412 MI SWACO Bob Myles Warehouse Manager rmyles@miswaco.com 907 776-8680 907 252-4218 MI SWACO Michael Barry Senior Field barry.michael@att.net 907 260-4666 907 590-3636 MI SWACO Engineer (home) Locke Rooney Field Engineer rooneyl@alaska.net 907 235-0598 907 590-3636 MI SWACO (home) Dave Morris/ John Drilling Foremen alaska_drilling 907 283-1312 Nicholson @marathonoil.com Marathon Responsibilities - MI Project Engineer and will coordinate daily between the Marathon office, rig, warehouse, and the M-I field engineers. - Well progress will be monitored to look for any changes, which will improve the efficiency of the operation or avert trouble. - Field Engineers will monitor and supervise product inventory to include re-palletizing any products for shipment to other locations at the end of the well. - Field Engineers will communicate with office personnel (Marathon & MI SWACO) for approval of any changes in the mud program (including introduction of new products). - Field Engineers will produce a recap at the end of the well based on daily activities. Recap should include any lessons learned that may be used to provide better service on future wells. Lessons learned can include changes in procedures, product additions, equipment usage, and/or utilization of any third party service. ~~ Check No Check Date Bank Bank No Vendor N Marathon Oil Company Direct Inquiries to: ACCOUNTS PAYABLE DEPARTMENT Hndi g P. O. Box 22164 C t C 1226707 06/19/2006 NCBAS 7780 500 1123 Tulsa, OK 74 1 21-21 64 en er ontact Accts Payable phone: 918-925-6097 HS inVGICQNu7rib2t InvolceDate DPcumesitNO RemitCatrtmerlt C~ossAmount Discount Iruaice/PaYArstount L100.00 06/19/2006 1900029734 TorAL: 100.00 100.00 100.0 100.0 ON PERFORATION BELOW AND DETACH CHECK STU6 BEf-OHE uEP051 I iNG) V: 5/00 ~~ ACCOUNTS PAYABL , E CHECK ~w'?i' PAY TO THE ORDER OF: ~~ • ~` E''A ' L &A'S' CONSERVATION COMMISSION € 333; WEST 7TH AVE STE 100 ANCHORAGE, AK 99501-3 Mara ~ ~ ~ Oilti'Ca~-pa~r-,y P .,Box 22164 Tulsa, OK 74121-2164 _ G'.,5. hu~uls eNATCO . ITI~~BANFS Ashlandre~h~io ~~'000 L 2 26 70 7~~' x:04 L 20 389 5~: 0 LB 3484~i' • • TRANSMITTAL LETTER CHECKLIST ~' ~ ~~ WELL NAME J ~~SG,~ ,~ fJ~ PTD# 2c~-'og~g' Development Service Exploratory Stratigraphic Test Non-Conventional Well Circle Appropriate Letter /Paragraphs to be Included in Transmittal Letter CHECK ADD-ONS TEXT FOR APPROVAL LETTER WHAT (OPTIONS) APPLIES MULTI LATERAL The permit is for a new wellbore segment of existing well (If last two digits in permit No. API No. 50- - - API number are , between 60-69) Production should continue to be reported as a function of the original API number stated above. PILOT HOLE In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name ( PH) and API number (50- - -) from records, data and logs acquired for well SPACING The permit is approved subject to full compliance wit AAC EXCEPTION 25.055. Approva and roduce / in'e ~s contingent upon issuance of a conservatio der roving a spacing exception. assumes the liability of any protest t>~e-~sp~ cmg exception that ccur. DRY DITCH All dry ditch sample sets submitted to the Commission must be in SAMPLE no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: Non-Conventional production or production testing of coal bed methane is not allowed Well for (name of well) until after Company NameZhas designed and implemented a water well testing program to provide baseline data on water quality and quantity. Company NameZmust contact the Commission to obtain advance approval of such water well testing ro ram. Rev: 1!25/06 C:\jody\transmittal_checklist N°7~` s_ , ,~~ e".~ ;~ 1$ Prop NlhllLf'HIK ti~ TY LL ~ -_~~ (,~.~+,~~2„'~ F,~ ~ ON~K IINDEF GAS - 562560 i,1~e i nr, ,r;; NINILCHIK UN!T S DIONNE 5 Program DEV _ _ Well bore seg Pl J# 2uct .. ^ "~ -~^any ~ iHrtFl-~~1 v ~!'- CO _ ~~~~ i~l C ~~>"' ;~pe DEV 11 Gi;;~ ~>w~~~~ Unif i~nlOif Shore ~n Nrru ar Disposal Administration 1 Fermit fee attacnetl Yes .-.. 2 i.caiiE r~umaer appropriate Yes 3 j.niyue well narne and number Yes 4 ~a1e,l vcriied iri a defined pool No a ins ~ ~ !ocak2d r,.,pe- .~i_stanc~ from dr Ifing unit boundaryy_ No The predpctw~~ rn,rrtion of this well 6 'aJel, loc;aed proper distance trorn other wells Yes is expected to be within 1500' of 7 ,°;~ricieri acreage available in drilling unit Yes a properly boundary with different c If leviated, is wellbore plat ir~cluded Yes lantlcwners. Fee average 9 Operator only affected party Yes uutside of the current Susan Dionne 10 G~perator has appropriate bond in force Yes PA in the Ninilchic Expl. Unit-RPC 11 Permit can be issued without conservation order. No Spacing Exception Drafted 6130 12 Permit can be issued without administrative-approval Yes Appr Date 13 Can permit be approved before 15-day wait No With a signed spacing exception only RPC 61301?006 1u NJell loi.ated within area and strata authorized by Injection Order # (put 10# in comments) (For NA 15 ;a wells within 1!4-mile area of review identified (For service well only). NA 16 Pre-produced injector:. duration ofpre-production less than. 3months-(For service well only) NA_ 17 Nonconven. gas conforms to A$31,05,030Q,1.A),Q,2.A-p) No 18 _ Conductor stung provided _ Yes _ 20" @ 91' Engineering 19 Surface casing protects all known USDWs Yes 20 CMT vol. adequate to circulate on conductor & surf csg Yes Adequate excess. 21 CMT vol adequate to tie-in long string to surf csg Yes 22 CMT will cover all known productive horizons- Yes I23 Casing designs adequate for C, T, B & permafrost_ Yes 24 Adequate Tankage or reserve pit Yes Glacier Rig t 25 If a re-drill., has a 10-4.03 for abandonment been approved NA _ New well. 26 Adequate wellbore separation proposed Yes 27 If diverter required., does it meet regulations.. Yes '28 Drilling fluid. program schematic & equip list adequate_ Yes Max. MW 9.8 ppg. Appr Date 7.9 BOPEs, do they meet regulation Yes WGA 6/3012006 30 BOPEpress rating appropriate; test ko (put prig in cgmments) Yes Test to 3000. psi.. MSP 2509 psi.- '31 Choke_manifgld complies wlAPl_RP-53 (May 84)_ - - Yes 32 Wgrk will occur without operation shutdgwn Yes '33 Is presence of H2S gas. probable No Not an H2S area. 34 Mechanical condition of wells within AOR verified (For-service well only) N_A 35 Permit can be issued wlo hydrogen sulfide measures Yes Geology i36 Data presented on. potential overpressure zones NA_ . '~37 Seismic analysis. of shallow gas zones. _ NA_ Appr Date 138 Seabed condition survey (if offshore) NA_ RPC 6/2112006 139 Contact namelphone for weekly_progress reports. [exploratory only] NA Geologic Engineering Public Commissioner: Date: o issioner: Date Commissioner Date •